Enhancing Oil Recovery in Low-Permeability Reservoirs Using a Low-Molecular Weight Amphiphilic Polymer

Polymer flooding has achieved considerable success in medium-high permeability reservoirs. However, when it comes to low-permeability reservoirs, polymer flooding suffers from poor injectivity due to the large molecular size of the commonly used high-molecular-weight (high-MW) partially hydrolyzed polyacrylamides (HPAM). Herein, an amphiphilic polymer (LMWAP) with a low MW (3.9 × 106 g/mol) was synthesized by introducing an amphiphilic monomer (Allyl-OP-10) and a chain transfer agent into the polymerization reaction. Despite the low MW, LMWAP exhibited better thickening capability in brine than its counterparts HPAM-1800 (MW = 1.8 × 107 g/mol) and HPAM-800 (MW = 8 × 106 g/mol) due to the intermolecular hydrophobic association. LMWAP also exhibited more significant shear-thinning behavior and stronger elasticity than the two counterparts. Furthermore, LMWAP possesses favorable oil-water interfacial activity due to its amphiphilicity. The oil-water interfacial tension (IFT) could be reduced to 0.88 mN/m and oil-in-water (O/W) emulsions could be formed under the effect of LMWAP. In addition, the reversible hydrophobic association endows the molecular chains of LMWAP with dynamic association-disassociation transition ability. Therefore, despite the similar hydrodynamic sizes in brine, LMWAP exhibited favorable injectivity under low-permeability conditions, while the counterpart HPAM-1800 led to fatal plugging. Furthermore, LMWAP could enhance oil recovery up to 21.5%, while the counterpart HPAM-800 could only enhance oil recovery by up to 11.5%, which could be attributed to the favorable interfacial activity of LMWAP.

Synthesis, Characterization, and Properties of a Novel Hyperbranched Polymers with Polyacrylamide Side Chains

A novel hyperbranched polymer with polyacrylamide side chains (HAPAM) was synthesized by aqueous solution polymerization using acrylic acid, acrylamide, 2-acrylamido-2-methyl-1-propanesulfonic acid, hydrophobic monomer of dimethyl octadecyl ammonium chloride, and the homemade skeleton monomer of modified-M2.0 as raw materials and (NH4)2S2O8-NaHSO3 as initiator. The molecular structure, functional groups, and surface morphology of HAPAM were characterized by Fourier transform infrared spectroscopy, nuclear magnetic resonance hydrogen spectroscopy, and scanning electron microscopy. It was found that the performance of HAPAM solution was higher than that of ordinary polyacrylamide solution in terms of thickening ability, shearing resistance, thermal endurance, salt-resistance, resistance-coefficient and residual-resistance-coefficient, ability to reduce interfacial tension between polymer solution and crude oil, and oil-displacement-efficiency. In particular, the enhanced oil recovery of the HAPAM solution was 13.03%, and the improvement of shearing resistance and immunity to chromatographic separation were simultaneously achieved by the HAPAM solution. These results indicate that the successful synthesis of the novel HAPAM opens a promising strategy for developing new high-performance oil-displacing polymers.

Evaluation of Profile Control and Oil Displacement Effect of Starch Gel and Nano-MoS2 Combination System in High-Temperature Heterogeneous Reservoir

The Henan Oilfield's medium-permeability blocks face challenges such as high temperatures and severe heterogeneity, making conventional flooding systems less effective. The starch gel system is an efficient approach for deep profile control in high-temperature reservoirs, while the nano-MoS2 system is a promising enhanced oil recovery (EOR) technology for high-temperature low-permeability reservoirs. Combining these two may achieve the dual effects of profile control and oil displacement, significantly enhancing oil recovery in high-temperature heterogeneous reservoirs. The basic performance evaluation of the combination system was carried out under reservoir temperature. Displacement experiments were conducted in target blocks under different permeabilities and extreme disparity core flooding to evaluate the combination system's oil displacement effect. Additionally, the displacement effects and mechanisms of the starch gel and nano-MoS2 combination system in heterogeneous reservoirs were evaluated by simulating interlayer and intralayer heterogeneity models. The results show that the single nano-MoS2 system's efficiency decreases with increased core permeability, and its effectiveness is limited in triple and quintuple disparity parallel experiments. After injecting the starch gel-nano-MoS2 combination system, the enhanced oil recovery effect was significant. The interlayer and intralayer heterogeneous models demonstrated that the primary water flooding mainly affected the high-permeability layers, while the starch gel effectively blocked the dominant channels, forcing the nano-MoS2 oil displacement system towards unswept areas. This coordination significantly enhanced oil displacement, with the combination system improving recovery by 15.33 and 12.20 percentage points, respectively. This research indicates that the starch gel and nano-MoS2 combination flooding technique holds promise for enhancing oil recovery in high-temperature heterogeneous reservoirs of Henan Oilfield, providing foundational support for field applications.

Study on the Structure-Activity Relationship and Oil Displacement Characteristics of the Polysurfactant Agent

This study examines a versatile polymer known as polysurfactant, which is synthesized by co-polymerizing flexible acrylamide and sodium acrylate hydrocarbon chain. The polymer serves as a backbone and possesses active functional groups. Notably, the polysurfactant exhibits superior plugging and flooding abilities compared to conventional polymers. The primary objective of this paper is to investigate the properties and oil displacement characteristics of the polysurfactant through indoor physical simulation experiments. The results demonstrate that the multi-branched structure of the polysurfactant enhances its ability to associate, leading to the formation of a unique spatial network structure. The inclusion of multi-branched structures notably amplifies the association effect. The critical concentration for the association is estimated to be around 800 mg/L, at which juncture the polysurfactant exhibits a viscosity retention rate surpassing 90% subsequent to shearing. Furthermore, this spatial network structure exhibits self-recovery capabilities after experiencing shear failure and displaying strong viscosity and shear resistance. In addition, the concentration of the polysurfactant can control the hydrodynamic feature size, which shows its adaptability in regulation and oil-repelling functions at reservoir permeabilities ranging from 500 to 2000 × 10-3 μm2 with resistance coefficients ranging from 108 to 320. During the microscopic oil displacement process, the polysurfactant exerts a significant impact on mobility control, while the elastic pull clearly demonstrates a commendable viscoelastic oil displacement effect. The polysurfactant exhibits a specific degree of emulsification capability towards crude oil, leading to the emulsion exhibiting typical pseudoplastic fluid characteristics. The utilization of emulsification transportation and emulsification blockage contributes to the enhancement of oil recovery. As a result, the polysurfactant exhibits multifaceted capabilities, encompassing profile control, flooding, and plugging, owing to its unique structural characteristics. Through the implementation of a field test focused on flooding in the Daqing Oilfield, a significant enhancement in the recovery rate of 10.85% is observed, accompanied by a favorable input-output ratio of 1:3.86, thereby generating significant economic advantages.

Experimental Investigation of the Viscosity and Stability of Scleroglucan-Based Nanofluids for Enhanced Oil Recovery

Biopolymers emerge as promising candidates for enhanced oil recovery (EOR) applications due to their molecular structures, which exhibit better stability than polyacrylamides under harsh conditions. Nonetheless, biopolymers are susceptible to oxidation and biological degradation. Biopolymers reinforced with nanoparticles could be a potential solution to the issue. The nanofluids' stability and performance depend on the nanoparticles' properties and the preparation method. The primary objective of this study was to evaluate the effect of the preparation method and the nanoparticle type (SiO2, Al2O3, and TiO2) on the viscosity and stability of the scleroglucan (SG). The thickening effect of the SG solution was improved by adding all NPs due to the formation of three-dimensional structures between the NPs and the SG chains. The stability test showed that the SG + Al2O3 and SG + TiO2 nanofluids are highly unstable, but the SG + SiO2 nanofluids are highly stable (regardless of the preparation method). According to the ANOVA results, the preparation method and standing time influence the nanofluid viscosity with a statistical significance of 95%. On the contrary, the heating temperature and NP type are insignificant. Finally, the nanofluid with the best performance was 1000 ppm of SG + 100 ppm of SiO2_120 NPs prepared by method II.

New Trends in Biosurfactants: From Renewable Origin to Green Enhanced Oil Recovery Applications

Enhanced oil recovery (EOR) processes are technologies used in the oil and gas industry to maximize the extraction of residual oil from reservoirs after primary and secondary recovery methods have been carried out. The injection into the reservoir of surface-active substances capable of reducing the surface tension between oil and the rock surface should favor its extraction with significant economic repercussions. However, the most commonly used surfactants in EOR are derived from petroleum, and their use can have negative environmental impacts, such as toxicity and persistence in the environment. Biosurfactants on the other hand, are derived from renewable resources and are biodegradable, making them potentially more sustainable and environmentally friendly. The present review intends to offer an updated overview of the most significant results available in scientific literature on the potential application of biosurfactants in the context of EOR processes. Aspects such as production strategies, techniques for characterizing the mechanisms of action and the pros and cons of the application of biosurfactants as a principal method for EOR will be illustrated and discussed in detail. Optimized concepts such as the HLD in biosurfactant choice and design for EOR are also discussed. The scientific findings that are illustrated and reviewed in this paper show why general emphasis needs to be placed on the development and adoption of biosurfactants in EOR as a substantial contribution to a more sustainable and environmentally friendly oil and gas industry.

Mechanistic Insights into a Novel Controllable Phase-Transition Polymer for Enhanced Oil Recovery in Mature Waterflooding Reservoirs

Expanding swept volume technology via continuous-phase polymer solution and dispersed-phase particle gel is an important technique to increase oil production and control water production in mature waterflooding reservoirs. However, problems such as the low viscosity retention rate, deep migration, and weak mobility control of conventional polymers, and the contradiction between migration distance of particle gel and plugging strength, restrict the long-term effectiveness of oil displacement agents and the in-depth sweep efficiency expanding capability in reservoirs. Combined with the technical advantages of polymer and particle gel, a novel controllable phase-transition polymer was developed and systematically studied to gain mechanistic insights into enhanced oil recovery for mature waterflooding reservoirs. To reveal the phase-transition mechanism, the molecular structure, morphology, and rheological properties of the controllable phase-transition polymer were characterized before and after phase transition. The propagation behavior of the controllable phase-transition polymer in porous media was studied by conducting long core flow experiments. Two-dimensional micro visualization and parallel core flooding experiments were performed to investigate the EOR mechanism from porous media to pore level. Results show that the controllable phase-transition polymer could change phase from dispersed-phase particle gel to continuous-phase solution with the prolongation of ageing time. The controllable phase-transition polymer exhibited phase-transition behavior and good propagation capability in porous media. The results of micro visualization flooding experiments showed that the incremental oil recovery of the controllable phase-transition polymer was highest when a particle gel and polymer solution coexisted, followed by a pure continuous-phase polymer solution and pure dispersed-phase particle gel suspension. The recovery rate of the novel controllable phase-transition polymer was 27.2% after waterflooding, which was 8.9% higher than that of conventional polymer, providing a promising candidate for oilfield application.

Novel Environmentally Responsive Polyvinyl Polyamine Hydrogels Capable of Phase Transformation with Temperature for Applications in Reservoir Profile Control

Hydrogel has been widely used in reservoir regulation for enhancing oil recovery, however, this process can experience negative influences on the properties and effects of the hydrogels. Therefore, developing novel hydrogels with excellent environmental responsiveness would improve the formation adaptability of hydrogels. In this study, novel polyvinyl polyamine hydrogels were synthesized by a ring-opening addition reaction between polyvinyl polyamines and polyethylene glycol glycidyl ether. The results of atomic force microscopy and transmission electron microscopy showed that the polyvinyl polyamine gel had a porous and irregular bulk structure and was endowed with water storage. With the temperature rising from 30 °C to 60 °C, the transmittance of diethylenetriamine hydrogel decreased from 84.3% to 18.8%, indicating that a phase transition had occurred. After the polyvinyl polyamine hydrogel with low initial viscosity was injected into the formation in the liquid phase, the increase of the reservoir temperature caused it to turn into an elastomer, thereby migrating to the depth of the reservoir and achieving effective plugging. Polyvinyl polyamine hydrogel could improve the profile of heterogeneous layers significantly by forcing subsequent fluids into the low permeability zone in the form of elastomers in the medium temperature reservoirs of 40-60 °C. The novel environmentally responsive polyvinyl polyamine hydrogels, capable of phase transformation with temperature, exhibited superior performance in recovering residual oil, which was beneficial for applications in reservoir profile control and oilfield development.

Preparation and Performance Evaluation of Amphiphilic Polymers for Enhanced Heavy Oil Recovery

The continuous growth in global energy and chemical raw material demand has drawn significant attention to the development of heavy oil resources. A primary challenge in heavy oil extraction lies in reducing crude oil viscosity. Alkali-surfactant-polymer (ASP) flooding technology has emerged as an effective method for enhancing heavy oil recovery. However, the chromatographic separation of chemical agents presents a formidable obstacle in heavy oil extraction. To address this challenge, we utilized a free radical polymerization method, employing acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, lauryl acrylate, and benzyl acrylate as raw materials. This approach led to the synthesis of a multifunctional amphiphilic polymer known as PAALB, which we applied to the extraction of heavy oil. The structure of PAALB was meticulously characterized using techniques such as infrared spectroscopy and Nuclear Magnetic Resonance Spectroscopy. To assess the effectiveness of PAALB in reducing heavy oil viscosity and enhancing oil recovery, we conducted a series of tests, including contact angle measurements, interfacial tension assessments, self-emulsification experiments, critical association concentration tests, and sand-packed tube flooding experiments. The research findings indicate that PAALB can reduce oil-water displacement, reduce heavy oil viscosity, and improve swept volume upon injection into the formation. A solution of 5000 mg/L PAALB reduced the contact angle of water droplets on the core surface from 106.55° to 34.95°, shifting the core surface from oil-wet to water-wet, thereby enabling oil-water displacement. Moreover, A solution of 10,000 mg/L PAALB reduced the oil-water interfacial tension to 3.32 × 10-4 mN/m, reaching an ultra-low interfacial tension level, thereby inducing spontaneous emulsification of heavy oil within the formation. Under the condition of an oil-water ratio of 7:3, a solution of 10,000 mg/L PAALB can reduce the viscosity of heavy oil from 14,315 mPa·s to 201 mPa·s via the glass bottle inversion method, with a viscosity reduction rate of 98.60%. In sand-packed tube flooding experiments, under the injection volume of 1.5 PV, PAALB increased the recovery rate by 25.63% compared to traditional hydrolyzed polyacrylamide (HPAM) polymer. The insights derived from this research on amphiphilic polymers hold significant reference value for the development and optimization of chemical flooding strategies aimed at enhancing heavy oil recovery.

Research Progress in Nanofluid-Enhanced Oil Recovery Technology and Mechanism

Nanofluid-enhanced oil recovery (EOR) technology is an innovative approach to enhancing oil production in oilfields. It entails the dispersion of nanoparticles within a fluid, strategically utilizing the distinctive properties of these nanoparticles (NPs) to engage with reservoir rocks or crude oil, resulting in a significant enhancement of the oil recovery rate. Despite the notable advantages of nanofluid EOR technology over conventional oil recovery methods such as binary and ternary flooding, practical implementations continue to grapple with a range of pressing challenges. These challenges encompass concerns regarding the economic viability, stability, and adaptability of nanomaterials, which pose significant barriers to the widespread adoption of nanofluid EOR technology in the oil field. To tackle these challenges, addressing the current issues may involve selecting simpler and more readily available materials coupled with straightforward material modification techniques. This approach aims to more effectively meet the requirements of large-scale on-site applications. Within this framework, this review systematically explores commonly employed nanofluids in recent years, including inorganic nanofluids, organic nanofluids, and composite nanofluids. It categorizes the research advancements in optimizing modification techniques and provides a comprehensive overview of the mechanisms that underpin nanofluid EOR technology and its practical applications in oilfields. This comprehensive review aims to offer valuable references and serve as a solid foundation for subsequent research endeavors.

Exploring Potential of Gellan Gum for Enhanced Oil Recovery

Extensive laboratory and field tests have shown that the gelation response of gellan gum to saline water makes it a promising candidate for enhanced oil recovery (EOR). The objective of this mini-review is to evaluate the applicability of gellan gum in EOR and compare its efficiency to other precursors, in particular, hydrolyzed polyacrylamide (HPAM). At first, the "sol-gel" phase transitions of gellan gum in aqueous-salt solutions containing mono- and divalent cations are considered. Then the rheological and mechanical properties of gellan in diluted aqueous solutions and gel state are outlined. The main attention is paid to laboratory core flooding and field pilot tests. The plugging behavior of gellan in laboratory conditions due to "sol-gel" phase transition is discussed in the context of conformance control and water shut-off. Due to its higher strength, gellan gum gel provided ~6 times greater resistance to the flow of brine in a 1 mm-width fracture compared to HPAM gel. The field trials carried out in the injection and production wells of the Kumkol oilfield, situated in Kazakhstan, demonstrated that over 6 and 11 months, there was an incremental oil recovery of 3790 and 5890 tons, respectively. To put it into perspective, using 1 kg of dry gellan resulted in the incremental production of 3.52 m3 (or 22 bbls) of oil. The treatment of the production well with 1 wt.% gellan solution resulted in a considerable decrease in the water cut up to 10-20% without affecting the oil flow rate. The advantages and disadvantages of gellan compared to HPAM are analyzed together with the economic feasibility of gellan over HPAM. The potential for establishing gellan production in Kazakhstan is emphasized. It is anticipated that gellan gum, manufactured through fermentation using glucose-fructose syrup from Zharkent and Burunday corn starch plants, could be expanded in the future for applications in both the food industry and oil recovery.

Matching method between nanoparticle displacement agent size and pore throat in low permeability reservoir

Nano-particles possess desirable attributes such as small particle size, excellent injectivity, and migration performance, making them highly compatible and adaptable for addressing the water flooding requirements of the low-permeability oil reservoir. When selecting an oil displacement agent for enhancing water flooding and improving oil recovery, factors such as injectivity and migration need to be carefully considered. In this study, through a comprehensive analysis of the mechanism and technical characteristics of nano-particle oil displacement agents, the plugging and profile control mechanisms recognized by the mainstream of nano-particles are elucidated. By examining various elements including outcrop fractures, natural micro-fractures, artificial support fractures, and dynamic monitoring data, a reevaluation of the dominant channel scale governing water drive in low permeability reservoirs is conducted, thereby defining the target entities for profile control and flooding operations. Drawing upon Darcy's percolation law and leveraging enhanced oil recovery techniques based on the classical Kozeny equation, a profile control and flooding mechanism is proposed that focuses on increasing the specific surface area of polymer particles while simultaneously reducing reservoir permeability. This innovative approach establishes a novel matching method between nano-polymer particles and the diverse media found within the reservoir. Lastly, the application of nanoparticle flooding technology in Changqing Oilfield is presented, highlighting its practical implementation and benefits.

Development of a Novel High-Temperature Microemulsion for Enhanced Oil Recovery in Tight Oil Reservoirs

This work focuses on the development of a novel high-temperature microemulsion for enhanced oil recovery in tight oil reservoirs. Microemulsions are a type of mixture that has properties of both liquids and solids; they have shown significant potential for improving oil recovery through spontaneous imbibition. Herein, a high-temperature-tolerant lower-phase microemulsion using a microemulsion dilution method was developed. The properties and morphological characteristics of the microemulsion were evaluated and proposed a mechanism for enhanced spontaneous imbibition oil recovery using imbibition tests and CT scanning technology. The results of the study showed that the optimum concentration of the microemulsion was 0.2 wt% and that it had good thermal stability, small droplet size, lower interfacial tension, good wettability alteration ability, and minimum adsorption loss. The imbibition and CT experiments demonstrated that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. The study concludes that the solubilization coefficient and self-driving force were defined and calculated to quantitatively analyze the imbibition mechanisms and the results showed that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force.

Effect of Salt Concentration on Oil Recovery during Polymer Flooding: Simulation Studies on Xanthan Gum and Gum Arabic

Oil recoveries from medium and heavy oil reservoirs under natural recovery production are small because of the high viscosity of the oil. Normal water flooding procedures are usually ineffective, as the injected water bypasses much of the oil because of its high mobility. Thermal flooding processes are desirable but have many disadvantages from costs, effects on the environment, and loss of lighter hydrocarbons. Chemical flooding options, such as bio-polymer flooding options, are attractive, as they are environmentally friendly and relatively cheap to deploy and help to increase the viscosity of the injecting fluid, thereby reducing its mobility and increasing its oil recovery. The downside to polymer flooding includes reservoir temperature, salinity, molecular weight, and composition. Six weight percentages of two polymers (xanthan gum, XG, and gum arabic, GA) are dissolved in water, and their viscosity is measured in the laboratory. These viscosities are incorporated with correlations in the Eclipse software to create models with different polymer concentrations of (0.1% wt., 0.2% wt., 0.3% wt., 0.4% wt., 0.5% wt., and 1% wt.). A base case of natural recovery and water injection was simulated to produce an oil recovery of 5.9% and 30.8%, respectively, while at 0.1% wt. and 1% wt., respectively, oil recoveries of 38.8% and 45.7% (for GA) and 48.1% and 49.8% (for XG) are estimated. At 5% and 10% saline conditions, a drop in oil recovery of (4.6% and 5.3%) is estimated during GA flooding and (1.2% and 1.7%) for XG flooding at 1% wt., respectively. XG exhibits higher oil recoveries compared to GA at the same % wt., while oil recoveries during GA floodings are more negatively affected by higher saline concentrations.

Experimental Study on Enhanced Oil Recovery of Adaptive System after Polymer Flooding

After polymer flooding in Daqing Oilfield, the heterogeneity of the reservoir is enhanced, leading to the development of the dominant percolation channels, a significant issue with inefficient circulation, a substantial amount of displacement agents, and elevated cost. In order to further improve oil recovery, an adaptive oil displacement system (ASP-PPG) was proposed by combining preformed particle gel (PPG) with an alkali-surfactant-polymer system (ASP). This comprehensive study aims to assess the effectiveness of the adaptive oil displacement system (ASP-PPG) in improving the recovery efficiency of heterogeneous reservoirs after polymer flooding. The evaluation encompasses various critical aspects, including static performance tests, flow experiments, microscopic experiments, profile control experiments, and flooding experiments conducted on a four-layer heterogeneous physical model. The experimental results show that the adaptive system has robust stability, enhanced mobility, effective plugging capability, and profile improvement capability. Notably, the system demonstrates the remarkable ability to successfully pass through the core and effectively block the large pores, resulting in an 18.4% recovery incremental after polymer flooding. This improvement is reflected in the reduced oil saturation values in the ultra-high permeability, high permeability, medium, and low permeability layers, which are 5.09%, 7.01%, 13.81%, and 15.45%, respectively. The adaptive system effectively recovered the remaining oil in the low and medium permeability layers, providing a promising approach for improving the recovery factors under challenging reservoir conditions.

Application of Hydrogels and Hydrocarbon-Based Gels in Oil Production Processes and Well Drilling

The use of gels in oil production processes has become a regular practice in oilfield operations and is constantly developing in all oil-producing countries of the world, as evidenced by the growth of publications and patent activity on this topic. Many oil production processes, such as hydraulic fracturing, conformance control, water, and gas shutoff, cannot be imagined without the use of gel technologies. Inorganic, organic, and hybrid gels are used, as well as foams, gel-forming, and gel-dispersed systems. The possibility of a broad control of structural and mechanical properties, thermal stability, and shear resistance by introducing microscale and nanoscale additives made hydrogels and hydrocarbon-based gels indispensable tools for oil engineers.

Difference in Step-Wise Production Rules of SP Binary Flooding for Conglomerate Reservoirs with Different Lithologies

The purpose of this study is to clarify the difference in oil production rules of conglomerate reservoirs with different pore structures during surfactant-polymer (SP) binary flooding and to ensure the efficient development of conglomerate reservoirs. In this paper, the full-diameter natural cores from the conglomerate reservoir of the Triassic Kexia Formation in the seventh middle block of the Karamay Oilfield (Xinjiang, China) are selected as the research objects. Two schemes of single constant viscosity (SCV) and echelon viscosity reducing (EVR) are designed to displace oil from three main oil-bearing lithologies, namely fine conglomerate, glutenite, and sandstone. Through comprehensive analysis of parameters, such as oil recovery rate, water content, and injection pressure difference, the influence of lithology on the enhanced oil recovery (EOR) of the EVR scheme is determined, which in turn reveals the differences in the step-wise oil production rules of the three lithologies. The experimental results show that for the three lithological reservoirs, the oil displacement effect of the EVR scheme is better than that of the SCV scheme, and the differences in recovery rates between the two schemes are 9.91% for the fine conglomerate, 6.77% for glutenite, and 6.69% for sandstone. By reducing the molecular weight and viscosity of the SP binary system, the SCV scheme achieves the reconstruction of the pressure field and the redistribution of seepage paths of chemical micelles with different sizes, thus, achieving the step-wise production of crude oil in different scale pore throats and enhancing the overall recovery of the reservoir. The sedimentary environment and diagenesis of the three types of lithologies differ greatly, resulting in diverse microscopic pore structures and differential seepage paths and displace rules of SP binary solutions, ultimately leading to large differences in the enhanced oil recoveries of different lithologies. The fine conglomerate reservoir has the strongest anisotropy, the worst pore throat connectivity, and the lowest water flooding recovery rate. Since the fine conglomerate reservoir has the strongest anisotropy, the worst pore throats connectivity, and the lowest water flooding recovery, the EVR scheme shows a good "water control and oil enhancement" development feature and the best step-wise oil production effect. The oil recovery rate of the two schemes for fine conglomerate shows a difference of 10.14%, followed by 6.36% for glutenite and 5.10% for sandstone. In addition, the EOR of fine conglomerate maintains a high upward trend throughout the chemical flooding, indicating that the swept volume of small pore throats gradually expands and the producing degree of the remaining oil in it gradually increases. Therefore, the fine conglomerate is the most suitable lithology for the SCV scheme among the three lithologies of the conglomerate reservoirs.

The Interfacial Dilational Rheology Properties of Betaine Solutions: Effect of Anionic Surfactant and Polymer

Interfacial dilational rheology is one of the important means to explore the interfacial properties of adsorption films. In this paper, the interfacial rheological properties of the mixed system of sulfobetaine ASB with a linear alkyl group and two anionic surfactants, petroleum sulfonate (PS) and alkyl polyoxyethylene carboxylate (AEC), were investigated by interfacial dilational rheology. The effect of the introduction of polymer hydrophobically modified polyacrylamide (HMPAM) on the interfacial properties of the mixed system was analyzed. In this experiment, the surfactant solution was used as the external phase and n-decane was used as the internal phase. A periodic sinusoidal disturbance of 0.1 Hz was applied to the n-decane droplets, and the changes of parameters such as droplet interfacial tension and interfacial area were monitored in real time with the help of a computer. The results show that the betaine ASB molecule responds to the dilation and compression of the interface through the change of ion head orientation, while the feedback behavior of petroleum sulfonate PS and AEC molecules embedded with oxygen vinyl groups in the molecule is diffusion and exchange between the interface and the bulk phase. Therefore, the interface film formed by ASB alone is higher, and the film formed by PS and AEC molecules alone is relatively lower. After adding two kinds of anionic surfactants to the betaine system, the ionic head of PS or AEC molecules will be attached to the positive center of the hydrophilic group of ASB molecules by electrostatic attraction and no longer adsorb and desorb with the interface deformation. The interfacial rheological properties of the compound system are still dominated by betaine, with higher dilational modulus and lower phase angle. When a small amount of HMPAM is added, or the content of hydrophobic monomer AMPS in the bulk phase is low, the intermolecular interaction at the interface is enhanced, the slow relaxation process is intensified, and the interfacial film strength is increased. As the content of AMPS further increases, hydrophobic blocks and surfactant molecules will form interfacial aggregates similar to mixed micelles at the oil-water interface, which will regulate the properties of the film by affecting the adsorption of surfactants at the interface. As long as the interfacial tension is the same, the properties of the interfacial film are the same. Based on the colloid interface science and the background of enhanced oil recovery, this study provides a reference for the field application of chemical flooding formulations.

Enhancing Oil Recovery by Polymeric Flooding with Purple Yam and Cassava Nanoparticles

Significant amounts of oil remain in the reservoir after primary and secondary operations, and to recover the remaining oil, enhanced oil recovery (EOR) can be applied as one of the feasible options remaining nowadays. In this study, new nano-polymeric materials have been prepared from purple yam and cassava starches. The yield of purple yam nanoparticles (PYNPs) was 85%, and that of cassava nanoparticles (CSNPs) was 90.53%. Synthesized materials were characterized through particle size distribution (PSA), Zeta potential distribution, Fourier transform infrared spectroscopy (FTIR), differential scanning calorimetry (DSC), and transmission electron microscopy (TEM). The performance of PYNPs in recovering oil was better than CSNPs, as found from the recovery experiments. Zeta potential distribution results confirmed the stability of PYNPs over CSNPs (-36.3 mV for PYNPs and -10.7 mV for CSNPs). The optimum concentration for these nanoparticles has been found from interfacial tension measurements and rheological properties, and it was 0.60 wt.% for PYNPs and 0.80 wt.% for CSNPs. A more incremental recovery (33.46%) was achieved for the polymer that contained PYNPs in comparison to the other nano-polymer (31.3%). This paves the way for a new technology for polymer flooding that may replace the conventional method, which depends on partially hydrolyzed polyacrylamide (HPAM).

Nanofluids of Amphiphilic Kaolinite-Based Janus Nanosheets for Enhanced Oil Recovery: The Importance of Stable Emulsion

To meet the increasing global demand for energy, better recovery of crude oil from reservoirs must be achieved using methods that are economical and environmentally benign. Here, we have developed a nanofluid of amphiphilic clay-based Janus nanosheets via a facile and scalable method that provides potential to enhance oil recovery. With the aid of dimethyl sulfoxide (DMSO) intercalation and ultrasonication, kaolinite was exfoliated into nanosheets (KaolNS) before being grafted with 3-methacryloxypropyl-triemethoxysilane (KH570) on the Alumina Octahedral Sheet at 40 and 70 °C to form amphiphilic Janus nanosheets (i.e., KaolKH@40 and KaolKH@70). The amphiphilicity and Janus nature of the KaolKH nanosheets have been well demonstrated, with distinct wettability obtained on two sides of the nanosheets, and the KaolKH@70 was more amphiphilic than the KaolKH@40. Upon preparing Pickering emulsion in a hydrophilic glass tube, the KaolKH@40 preferentially stabilized emulsions, while the KaolNS and KaolKH@70 tended to form an observable and high-strength elastic planar interfacial film at the oil-water interface as well as films climbing along the tube's surface, which were supposed to be the result of emulsion instability and the strong adherence of Janus nanosheets towards tube's surface. Subsequently, the KaolKH was grafted with poly(N-Isopropylacrylamide) (PNIPAAm), and the prepared thermo-responsive Janus nanosheets demonstrated a reversible transformation between stable emulsion and the observable interfacial films. Finally, when the samples were subjected to core flooding tests, the nanofluid containing 0.01 wt% KaolKH@40 that formed stable emulsions showed an enhanced oil recovery (EOR) rate of 22.37%, outperforming the other nanofluids that formed observable films (an EOR rate ~13%), showcasing the superiority of Pickering emulsions from interfacial films. This work demonstrates that KH-570-modified amphiphilic clay-based Janus nanosheets have the potential to be used to improve oil recovery, especially when it is able to form stable Pickering emulsions.

Microfluidic Study of Enhanced Oil Recovery during Flooding with Polyacrylamide Polymer Solutions

A series of experiments have been carried out on the flooding of microfluidic chips simulating a homogeneous porous structure with various displacement fluids. Water and polyacrylamide polymer solutions were used as displacement fluids. Three different polyacrylamides with different properties are considered. The results of a microfluidic study of polymer flooding showed that the displacement efficiency increases significantly with increasing polymer concentration. Thus, when using a 0.1% polymer solution of polyacrylamide grade 2540, a 23% increase in the oil displacement efficiency was obtained compared to water. The study of the effect of various polymers on the efficiency of oil displacement showed that the maximum efficiency of oil displacement, other things being equal, can be achieved using polyacrylamide grade 2540, which has the highest charge density among those considered. Thus, when using polymer 2515 with a charge density of 10%, the oil displacement efficiency increased by 12.5% compared to water, while when using polymer 2540 with a charge density of 30%, the oil displacement efficiency increased by 23.6%.

The Impact of 3D Prism Cavity for Enhanced Oil Recovery Using Different Nanomaterials

Enhanced oil recovery (EOR) has been offered as an alternative to declining crude oil production. EOR using nanotechnology is one of the most innovative trends in the petroleum industry. In order to determine the maximum oil recovery, the effect of a 3D rectangular prism shape is numerically investigated in this study. Using ANSYS Fluent software(2022R1), we develop a two-phase mathematical model based on 3D geometry. This research examines the following parameters: flow rate Q = 0.01-0.05 mL/min, volume fractions = 0.01-0.04%, and the effect of nanomaterials on relative permeability. The result of the model is verified with published studies. In this study, the finite volume method is used to simulate the problem, and we run simulations at different flow rates while keeping other variables constant. The findings show that the nanomaterials have an important effect on water and oil permeability, increasing oil mobility and lowering IFT, which increases the recovery process. Additionally, it has been noted that a reduction in the flow rate improves oil recovery. Maximum oil recovery was attained at a 0.05 mL/min flow rate. Based on the findings, it is also demonstrated that SiO2 provides better oil recovery compared to Al2O3. When the volume fraction concentration increases, oil recovery ultimately increases.

Experimental Study on Enhanced Oil Recovery of PPG/ASP Heterogeneous System after Polymer Flooding

Following the application of polymer flooding in Daqing Oilfield, the heterogeneity between different layers has intensified, resulting in the formation of more favorable seepage channels and cross-flow of displacement fluids. Consequently, the circulation efficiency has decreased, necessitating the exploration of methods to enhance oil recovery. This paper focuses on experimental research utilizing a newly developed precrosslinked particle gel (PPG) combined with alkali surfactant polymer (ASP) to create a heterogeneous composite system. This study aims to improve the efficiency of heterogeneous system flooding after polymer flooding. The addition of PPG particles enhances the viscoelasticity of the ASP system, reduces the interfacial tension between the heterogeneous system and crude oil, and provides excellent stability. The heterogeneous system has high resistance and residual resistance coefficients during the migration process in a long core model, achieving an improvement rate of up to 90.1% under the permeability ratio of 9 between high and low permeability layers. Employing heterogeneous system flooding after polymer flooding can increase oil recovery by 14.6%. Furthermore, the oil recovery rate of low permeability layers can reach 28.6%. The experimental results confirm that the application of PPG/ASP heterogeneous flooding after polymer flooding can effectively plug high-flow seepage channels and improve oil washing efficiency. These findings hold significant implications for further reservoir development after polymer flooding.

Application and Research Prospect of Functional Polymer Gels in Oil and Gas Drilling and Development Engineering

Polymer gel materials are formed by physically crosslinking and chemically crosslinking to form a gel network system with high mechanical properties and reversible performance. Due to their excellent mechanical properties and intelligence, polymer gel materials are widely used in biomedical, tissue engineering, artificial intelligence, firefighting and other fields. Given the current research status of polymer gels at home and abroad and the current application status of oilfield drilling, this paper reviews the mechanism of polymer gels formed by physically crosslinking and chemically crosslinking, summarizes the performance characteristics and the mechanism of action of polymer gels formed by non-covalent bonding, such as hydrophobic bonding, hydrogen bonding, electrostatic and Van der Waals interactions interactions, and covalent bonding such as imine bonding, acylhydrazone bonding and Diels-Alder reaction. The current status and outlook of the application of polymer gels in drilling fluids, fracturing fluids and enhanced oil recovery are also introduced. We expand the application fields of polymer gel materials and promote the development of polymer gel materials in a more intelligent direction.

Research on Adaptability Evaluation Method of Polymer by Nuclear Magnetic Resonance Technology

In order to study the matching relationship between polymer(HPAM) molecular weight and reservoir permeability, in this paper, the injection performance of polymers with different molecular weights in rock cores with different permeability is studied. Using nuclear magnetic resonance technology combined with conventional core displacement equipment, the change law of the displacement process was analyzed from three aspects of nuclear magnetic resonance T₂ spectrum, core layering, and imaging. Finally, the fluidity of the polymer solution in the core was analyzed by injection pressure control features. The experimental results show that the polymer solution with a molecular weight of 25 million has the best retention effect in the core flooding experiment and can stay in the dominant channel of the core for a long time to control the water flooding mobility. In rocks with a permeability of 500, 1000, and 2000 mD, subsequent water flooding can expand the swept volume by about 25% compared with polymer flooding. This method can effectively establish the adaptability matching relationship between the polymer molecular weight and the reservoir permeability.

Visualized Study on a New Preformed Particle Gels (PPG) + Polymer System to Enhance Oil Recovery by Oil Saturation Monitoring Online Flooding Experiment

After tertiary recovery from the oilfields, improving the production of the remaining hydrocarbon is always challenging. To significantly improve oil recovery, a heterogeneous composite flooding system has been developed with preformed particle gels (PPG) and polymers according to the technical approach of plugging and flooding combination. In addition, an oil saturation monitoring device and a large-scale 3D physical model were designed to better evaluate the performance of the technique. The evaluation results show that the viscosity, stability, and elasticity of the heterogeneous composite flooding system are better than the single polymer system. In addition, both systems exhibit pseudoplastic fluid characteristics and follow the principle of shear thinning. The results of seepage experiments showed that PPG migrates alternately in porous media in the manner of "piling plugging-pressure increasing-deformation migration". The heterogeneous composite system can migrate to the depths of the oil layer, which improves the injection profile. In the visualization experiment, the heterogeneous composite system preferentially flowed into the high-permeability layer, which increased the seepage resistance and forced the subsequent fluid to flow into the medium and low permeability layers. The average saturation of the high, medium, and low permeability layers decreased by 4.74%, 9.51%, and 17.12%, respectively, and the recovery factor was further improved by 13.56% after the polymer flooding.

Effect of Rheological Properties of Polymer Solution on Polymer Flooding Characteristics

Polymer flooding is an appropriate enhanced oil recovery (EOR) process that can increase macroscopic sweep efficiency. We examined two polymeric superpushers at different salinities (10,000 and 42,000 ppm of NaCl and 18,000 ppm of CaCl₂) and temperatures (30 to 75 °C) as polymer-flooding agents for the EOR process. Rheological and thixotropic tests were attempted to find shear viscosity change when the polymer solutions were introduced under different salinity and temperatures, followed by describing the rheological behavior with the two most common rheological models used for polymer solutions, and then a quadratic model with Design-Expert to detect the effective parameters. Core flooding tests were conducted afterward to determine the final proposed fluid. An increase in the concentration of monovalent ions and the addition of divalent ions adversely affected both types of polymers used, which was similar to the effects of a temperature increase. The Flopaam 3630S at 1000 ppm has more stability under harsh conditions and enables 22% and 38% oil recovery in carbonate and sandstone core rocks, respectively. Consequently, Flopaam 3630S can be the perfect polymer agent for different chemical flooding procedures in high-salinity oil reservoirs.

Selecting EOR Polymers through Combined Approaches-A Case for Flooding in a Heterogenous Reservoir

This work uses micromodel, core floods and Field-Flow Fractionation (FFF) evaluations to estimate the behaviour and key elements for selecting polymers to address heterogenous reservoirs. One of the approaches was to construct two-layered micromodels differing six times in permeability and based on the physical characteristics of a Bentheimer sandstone. Further, the impacts of injectivity and displacement efficiency of the chosen polymers were then assessed using single- and two-phase core tests. Moreover, FFF was also used to assess the polymers' conformity, gyration radii, and molecular weight distribution. For the polymer selection for field application, we weighted on the good laboratory performance in terms of sweep efficiency improvement, injectivity, and propagation. Based on the results, polymer B (highest MWD) performed the poorest. Full spectrum MWD measurement using Field-Flow Fractionation is a key in understanding polymer behavior. Heterogenous micromodel evaluations provided consistent data to subsequent core flood evaluations and were in alignment with FFF indications. Single-phase core floods performed higher injection velocities (5 m/d) in combination of FFF showed that narrower MWD distribution polymers (polymers A and C) have less retention and better injectivity. Two-phase core floods performed at low, reservoir representative velocities (1 ft/d) showed that Polymer B could not be injected, with pressure response staying at high values even when chase brine is injected. Adsorption values for all tested polymers at these conditions were high, however highest were observed in the case of polymer B. Overall, for the polymer selection for field application, we weighted on the good laboratory performance in terms of sweep efficiency improvement, injectivity, polymer retention, and propagation; all accounted in this work.

Spontaneous Imbibition Oil Recovery by Natural Surfactant/Nanofluid: An Experimental and Theoretical Study

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO₂ could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO₂ nanoparticles compared to amine-treated SiO₂ by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.

Immiscible Viscous Fingering: The Simulation of Tertiary Polymer Displacements of Viscous Oils in 2D Slab Floods

Immiscible viscous fingering in porous media occurs when a high viscosity fluid is displaced by an immiscible low viscosity fluid. This paper extends a recent development in the modelling of immiscible viscous fingering to directly simulate experimental floods where the viscosity of the aqueous displacing fluid was increased (by the addition of aqueous polymer) after a period of low viscosity water injection. This is referred to as tertiary polymer flooding, and the objective of this process is to increase the displacement of oil from the system. Experimental results from the literature showed the very surprising observation that the tertiary injection of a modest polymer viscosity could give astonishingly high incremental oil recoveries (IR) of ≥100% even for viscous oils of 7000 mPa.s. This work seeks to both explain and predict these results using recent modelling developments. For the 4 cases (µ_o/µ_w of 474 to 7000) simulated in this paper, finger patterns are in line with those observed using X-ray imaging of the sandstone slab floods. In particular, the formation of an oil bank on tertiary polymer injection is very well reproduced and the incremental oil response and water cut drops induced by the polymer are very well predicted. The simulations strongly support our earlier claim that this increase in incremental oil displacement cannot be explained solely by a viscous “extended Buckley-Leverett” (BL) linear displacement effect; referred to in the literature simply as “mobility control”. This large response is the combination of this effect (BL) along with a viscous crossflow (VX) mechanism, with the latter VX effect being the major contributor to the recovery mechanism.

Membrane Emulsification-A Novel Solution for Treatment and Reuse of Produced Water from Oil Field

Produced water (PW) is, by volume, the largest waste product of the oil- and gas-exploration industry and contains pollutants such as hydrocarbons and heavy metals. To meet the stringent environmental regulations, PW must be treated before discharging into the environment. The current study proposes a novel treatment method where PW is used to prepare oil-in-water emulsion with potential applications within the oil-exploration industry. The emulsions are prepared by applying hollow fiber membrane emulsification (ME) on PW, which inherently contains oil, as to-be-dispersed phase. The results demonstrate that the average droplet size of the emulsions is a function of pressure applied on to-be-dispersed phase and could be customized from 0.24 to 0.65 µm by varying the pressure from 0.25 to 1 bar, respectively. Stability of the emulsions was verified under high pressure and a temperature and storage period of more than 24 h. The calculations showed that an ME unit with <100 kg weight and <1 m3 volume is appropriate to transform the daily average volume of PW from the Danish part of the North Sea into the emulsions. The study provides a novel route, which also complies well with the requirements (low-weight and small spatial footprints) of the offshore oil rigs, to treat and reuse PW within the oil production process and, therefore, eliminates its environmental footprint.

Techno-Economic Assessment and Life Cycle Assessment of CO2-EOR

CO₂-enhanced oil recovery (EOR) can have less GHG emissions compared to conventional oil production methods. The economy of CO₂-EOR can significantly benefit from the recent rise of carbon prices in carbon markets due to its greenhouse gas (GHG) emission savings. This study conducted a life cycle assessment (LCA) of CO₂-EOR in major hydrocarbon provinces of the world. Estimated net GHG emissions of CO₂-EOR were compared with GHG emissions of average produced oil in the given country. When sourcing CO₂ from coal-fired power plants, Kazakhstan and China have net GHG emissions of CO₂-EOR of 276 and 380 kg CO₂ eq/bbl, respectively, which are lower than the GHG emission factor of average oil produced in each of them. Significantly lower GHG emissions of CO₂-EOR are observed in other hydrocarbon provinces (Iraq, Saudi Arabia, Kuwait, etc.), where CO₂ could be delivered from Natural Gas Combined Cycle (NGCC) power plants. However, the cost of CO₂ capture is higher at NGCC power plants than at coal-fired power plants. Further, we developed a techno-economic assessment (TEA) model of the CO₂-EOR and integrated it with LCA to thoroughly consider carbon credits in its economy. The model was built based upon previous investigations and used statistics from a large industrial data set of CO₂-EOR to produce accurate estimates of the CO₂-EOR economy. The technical model iteratively estimated the balance of three fluids (crude oil, CO₂, and water) in the CO₂-EOR system with a 25 year operational lifespan and obtained actual data for the LCA and TEA models. The model was simulated for the Kazakhstan case with its oil market conditions for a demonstration purpose. TEA results showed that, with the available low-cost CO₂ capture source or high CO₂ cost in carbon trading, CO₂-EOR can compete with current upstream projects in Kazakhstan by simultaneously increasing oil production and reducing GHG emissions.

Enhanced Oil Recovery Mechanism and Technical Boundary of Gel Foam Profile Control System for Heterogeneous Reservoirs in Changqing

The gel plugging and flooding system has a long history of being researched and applied, but the Changqing reservoir geological characteristics are complex, and the synergistic performance of the composite gel foam plugging system is not fully understood, resulting in poor field application. Additionally, the technique boundary chart of the heterogeneous reservoir plugging system has hardly appeared. In this work, reservoir models of porous, fracture, and pore-fracture were constructed, a composite gel foam plugging system was developed, and its static injection and dynamic profile control and oil displacement performance were evaluated. Finally, combined with the experimental studies, a technical boundary chart of plugging systems for heterogeneous reservoirs is proposed. The research results show that the adsorption effect of microspheres (WQ-100) on the surface of elastic gel particles-1 (PEG-1) is more potent than that of pre-crosslinked particle gel (PPG) and the deposition is mainly on the surface of PPG. The adsorption effect of PEG-1 on the surface of PPG is not apparent, primarily manifested as deposition stacking. The gel was synthesized with 0.2% hydrolyzed polyacrylamide (HPAM) + 0.2% organic chromium cross-linking agent, and the strength of enhanced gel with WQ-100 was higher than that of PEG-1 and PPG. The comprehensive value of WQ-100 reinforced foam is greater than that of PEG-1, and PPG reinforced foam, and the enhanced foam with gel has a thick liquid film and poor foaming effect. For the heterogeneous porous reservoir with the permeability of 5/100 mD, the enhanced foam with WQ-100 shows better performance in plugging control and flooding, and the recovery factor increases by 28.05%. The improved foam with gel enhances the fluid flow diversion ability and the recovery factor of fractured reservoirs with fracture widths of 50 μm and 180 μm increases by 29.41% and 24.39%, respectively. For pore-fractured reservoirs with a permeability of 52/167 mD, the PEG + WQ-100 microsphere and enhanced foam with WQ-100 systems show better plugging and recovering performance, and the recovery factor increases are 20.52% and 17.08%, 24.44%, and 21.43%, respectively. The smaller the particle size of the prefabricated gel, the more uniform the adsorption on the foam liquid film and the stronger the stability of the foam system. The plugging performance of the composite gel system is stronger than that of the enhanced gel with foam, but the oil displacement performance of the gel-enhanced foam is better than that of the composite gel system due to the "plug-flooding-integrated" feature of the foam. Combined with the plugging and flooding performance of each plugging system, a technique boundary chart for the plugging system was established for the coexisting porous, fracture, and pore-fracture heterogeneous reservoirs in Changqing Oilfield.

Experimental Research on Seepage Law and Migration Characteristics of Core-Shell Polymeric Nanoparticles Dispersion System in Porous Media

The nanoparticles dispersion system has complex migration characteristics and percolation law in porous media due to the interaction between the nanoparticles and porous media. In this paper, lab experiments were carried out to characterize the morphology, particle size distributions, and apparent viscosities of SiO2/P(MBAAm-co-AM) polymeric nanoparticle solution, investigate its migration characteristics in porous media, and probe its capability of enhanced oil recovery (EOR) in the reservoirs. Quartz microtubule, sand pack, and etched glass micromodels were used as the porous media in the flow and flooding experiments. Gray image-processing technology was applied to achieve oil saturation at different flooding stages in the micromodel for calculating the EOR of the SiO2/P(MBAAm-co-AM) polymeric nanoparticle solution. The results show that The SiO2/P(MBAAm-co-AM) polymeric nanoparticles are spherical with diameters ranging from 260 to 300 nm, and the thicknesses of the polymeric layers are in the range of 30-50 nm. As the swelling time increases from 24 to 120 h, the medium sizes of the SiO2/P(MBAAm-co-AM) polymeric nanoparticles increase from 584.45 to 1142.61 nm. The flow of the SiO2/P(MBAAm-co-AM) polymeric nanoparticles has obvious nonlinear characteristics and a prominent scale effect at a low-pressure gradient, and there should be an optimal matching relationship between its injection mass concentration and the channel size. The flow tests in the sand packs demonstrate that the SiO2/P(MBAAm-co-AM) polymeric nanoparticles can form effective plugging in the main flow channels at different permeability areas and can break through at the throat to fulfill the step-by-step profile control. Moreover, the profile control of the SiO2/P(MBAAm-co-AM) polymeric nanoparticles strengthens with an increase in their swelling time. The microscopic flooding experiment in the etched glass micromodel confirms that the SiO2/P(MBAAm-co-AM) polymeric nanoparticles can block dynamically and alternatively the channels of different sizes with the form of loose or dense networks to adjust the fluid flow diversion, improve the sweep efficiency, and recover more residual oil. The SiO2/P(MBAAm-co-AM) polymeric nanoparticles can achieve an enhanced oil recovery of 20.71% in the micromodel.

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.

Thermophysical Properties of Nanofluid in Two-Phase Fluid Flow through a Porous Rectangular Medium for Enhanced Oil Recovery

It is necessary to sustain energy from an external reservoir or employ advanced technologies to enhance oil recovery. A greater volume of oil may be recovered by employing nanofluid flooding. In this study, we investigated oil extraction in a two-phase incompressible fluid in a two-dimensional rectangular porous homogenous area filled with oil and having no capillary pressure. The governing equations that were derived from Darcy’s law and the mass conservation law were solved using the finite element method. Compared to earlier research, a more efficient numerical model is proposed here. The proposed model allows for the cost-effective study of heating-based inlet fluid in enhanced oil recovery (EOR) and uses the empirical correlations of the nanofluid thermophysical properties on the relative permeability equations of the nanofluid and oil, so it is more accurate than other models to determine the higher recovery factor of one nanoparticle compared to other nanoparticles. Next, the effect of nanoparticle volume fraction on flooding was evaluated. EOR via nanofluid flooding processes and the effect of the intake temperatures (300 and 350 K) were also simulated by comparing three nanoparticles: SiO2, Al2O3, and CuO. The results show that adding nanoparticles (<5 v%) to a base fluid enhanced the oil recovery by more than 20%. Increasing the inlet temperature enhanced the oil recovery due to changes in viscosity and density of oil. Increasing the relative permeability of nanofluid while simultaneously reducing the relative permeability of oil due to the presence of nanoparticles was the primary reason for EOR.

Extraction, characterization and evaluation of saponin-based natural surfactant for enhanced oil recovery

To minimize environmental impact and costs, natural surfactants are suggested as an ecologically sustainable replacement for synthetic surfactants. The aim of this work is to evaluate the efficiency of low-cost saponin-based natural surfactant (SBNS) from Vernonia amygdalina (VA) leaves for enhanced oil recovery (EOR). Furthermore, the study investigated the IFT behaviour of SBNS at oil-water interface and the emulsion behaviour and oil displacement efficiency of SBNS. The SBNS was obtained via ultrasonic extraction of dried VA leaves in a water bath, centrifuging the obtained liquid mixture and freeze drying to evaporate to dryness. Thereafter, Fourier-transform infrared spectroscopy (FTIR) and high-performance liquid chromatography were used to characterize the extracted SBNS. Moreover, tensiometer (Easy-Dyne KRUSS) was used to study the interfacial tension (IFT) behaviour of the SBNS at oil-water interface. Also, the SBNS ability to form stable emulsion in the presence of crude oil was determined. Finally, oil displacement by SBNS solution was investigated under simulated reservoir conditions (3000 psi and 100 °C) with high-pressure high-temperature (Fars EOR) core flooding equipment. The performance of SBNS was compared to commercial non-ionic surfactant 4-octylphenol polyethoxylated (TX-100). Experimental result indicated that the SBNS reduced the IFT at oil-water interface. The natural surfactant lowered the IFT of the oil-water interface from 18.0 to 0.97 mN/m. Moreover, emulsions formed with SBNS showed good stability characterized by a decrease in the median drop diameter with an increase in SBNS concentration. Finally, oil displacement test shows that oil recovery of TX-100 and SBNS increased by 9% and 15% original-oil-in-place (OOIP), respectively. Hence, SBNS is recommended as an appropriate substitute for conventional surfactant due to its inexpensive raw material, lower toxicity, and higher efficiency.

Experimental Pore-Scale Study of a Novel Functionalized Iron-Carbon Nanohybrid for Enhanced Oil Recovery (EOR)

Nanofluid flooding, as a new technique to enhance oil recovery, has recently aroused much attention. The current study considers the performance of a novel iron-carbon nanohybrid to EOR. Carbon nanoparticles was synthesized via the hydrothermal method with citric acid and hybridize with iron (Fe3O4). The investigated nanohybrid is characterized by its rheological properties (viscosity), X-ray diffraction (XRD), and Fourier transform infrared spectroscopy (FTIR) analysis. The efficiency of the synthetized nanoparticle in displacing heavy oil is initially assessed using an oil-wet glass micromodel at ambient conditions. Nanofluid samples with various concentrations (0.05 wt % and 0.5 wt %) dispersed in a water base fluid with varied salinities were first prepared. The prepared nanofluids provide high stability with no additive such as polymer or surfactant. Before displacement experiments were run, to achieve a better understanding of fluid-fluid and grain-fluid interactions in porous media, a series of sub-pore scale tests-including interfacial tension (IFT), contact angle, and zeta potential-were conducted. Nanofluid flooding results show that the nanofluid with the medium base fluid salinity and highest nanoparticle concertation provides the highest oil recovery. However, it is observed that increasing the nanofluid concentration from 0.05% to 0.5% provided only three percent more oil. In contrast, the lowest oil recovery resulted from low salinity water flooding. It was also observed that the measured IFT value between nanofluids and crude oil is a function of nanofluid concentration and base fluid salinities, i.e., the IFT values decrease with the increase of nanofluid concentration and base fluid salinity reduction. However, the base fluid salinity enhancement leads to wettability alteration towards more water-wetness. The main mechanisms responsible for oil recovery enhancement during nanofluid flooding is mainly attributed to wettability alteration toward water-wetness and micro-dispersion formation. However, the interfacial tension (IFT) reduction using the iron-carbon nanohybrid is also observed but the reduction is not significant.

Recent Advances in Functional Polymer Materials for Energy, Water, and Biomedical Applications: A Review

Academic research regarding polymeric materials has been of great interest. Likewise, polymer industries are considered as the most familiar petrochemical industries. Despite the valuable and continuous advancements in various polymeric material technologies over the last century, many varieties and advances related to the field of polymer science and engineering still promise a great potential for exciting new applications. Research, development, and industrial support have been the key factors behind the great progress in the field of polymer applications. This work provides insight into the recent energy applications of polymers, including energy storage and production. The study of polymeric materials in the field of enhanced oil recovery and water treatment technologies will be presented and evaluated. In addition, in this review, we wish to emphasize the great importance of various functional polymers as effective adsorbents of organic pollutants from industrial wastewater. Furthermore, recent advances in biomedical applications are reviewed and discussed.

Enhancing Oil Recovery from Low-Permeability Reservoirs with a Thermoviscosifying Water-Soluble Polymer

Water-soluble polymers, mainly partially hydrolyzed polyacrylamide (HPAM), have been used in the enhanced oil recovery (EOR) process. However, the poor salt tolerance, weak thermal stability and unsatisfactory injectivity impede its use in low-permeability hostile oil reservoirs. Here, we examined the adaptivity of a thermoviscosifying polymer (TVP) in comparison with HPAM for chemical EOR under simulated conditions (45 °C, 4500 mg/L salinity containing 65 mg/L Ca²⁺ and Mg²⁺) of low-permeability oil reservoirs in Daqing Oilfield. The results show that the viscosity of the 0.1% TVP solution can reach 48 mPa·s, six times that of HPAM. After 90 days of thermal aging at 45 °C, the TVP solution had 71% viscosity retention, 18% higher than that of the HPAM solution. While both polymer solutions could smoothly propagate in porous media, with permeability of around 100 milliDarcy, TVP exhibited stronger mobility reduction and permeability reduction than HPAM. After 0.7 pore volume of 0.1% polymer solution was injected, TVP achieved an incremental oil recovery factor of 13.64% after water flooding, 3.54% higher than that of HPAM under identical conditions. All these results demonstrate that TVP has great potential to be used in low-permeability oil reservoirs for chemical EOR.

Advances in the analytical methods for the determination of fluorinated aromatic carboxylic acids in aqueous matrices: A review

Fluorobenzoic acids are critically important chemical tracers in hydrothermal, geothermal, leaching, and oilfield applications. Particularly in oilfield applications, these tracers are used to investigate fluid flow paths between injector wells and producer wells, providing valuable information about the enhanced oil recovery process of the oil reservoirs. The detection limit of tracers is a vital subject in field reservoir work because the amount of chemical tracer that must be injected into the injector well is directly related to the amount detected at the producer well after migration and diffusion. The popularity of fluorinated benzoic acids as the tracers is due to their non-toxicity over radioactive tracers and low detection limit, which is determined using analytical techniques. This review focuses on the improvements/developments in extraction techniques such as solid-phase extraction and determination techniques such as gas chromatography coupled with mass spectrometry, liquid chromatography with mass spectrometry, isotope dilution gas chromatography-mass spectrometry, high-performance liquid chromatography, ion chromatography coupled with electrospray mass spectrometry, and so on for the analysis of fluorinated benzoic acids to achieve the lowest possible limit of concentration.

Syntheses of a Hyperbranched Polymer and Its Performance on Enhanced Oil Recovery

A hyperbranched carboxylate-type polymer was synthesized through esterification and carboxymethylation, and its performance on enhanced oil recovery was experimentally evaluated. The optimum condition for esterification was 8 h at 120°C, where 3% PTSA as the catalyst and 9:1 mol ratio of the AB₂ intermediate and trimethylolpropane were used. The optimum condition for carboxymethylation was 4 h at 80°C. The critical micelle concentration of the hyperbranched polymer was 433.63 mg/L, the Krafft point was 5°C, and the surface tension was lowered to 28 mN/m. In the range of 400–500 mg/L concentration, the adsorption onto the oil sand surface achieved equilibrium, and micellar solubilization reached 600 ml/mol. The interfacial tension can be lowered to a level of 10⁻² mN/m by the single use of the hyperbranched polymer, and the value further decreased to a level of 10⁻³ mN/m while being formulated with sodium dodecylsulfate or NaOH. Oil recovery of water flooding was further enhanced by the single use of a hyperbranched polymer or the combination of hyperbranched polymer/sodium dodecylsulfate. The latter exhibited more prosperous advantages in low-permeability reservoirs.

Visualizing and Quantifying Wettability Alteration by Silica Nanofluids

An aqueous suspension of silica nanoparticles or nanofluid can alter the wettability of surfaces, specifically by making them hydrophilic and oil-repellent under water. Wettability alteration by nanofluids has important technological applications, including for enhanced oil recovery and heat transfer processes. A common way to characterize the wettability alteration is by measuring the contact angles of an oil droplet with and without nanoparticles. While easy to perform, contact angle measurements do not fully capture the wettability changes to the surface. Here, we employed several complementary techniques, such as cryo-scanning electron microscopy, confocal fluorescence and reflection interference contrast microscopy, and droplet probe atomic force microscopy (AFM), to visualize and quantify the wettability alterations by fumed silica nanoparticles. We found that nanoparticles adsorbed onto glass surfaces to form a porous layer with hierarchical micro- and nanostructures. The porous layer can trap a thin water film, which reduces contact between the oil droplet and the solid substrate. As a result, even a small addition of nanoparticles (0.1 wt %) lowers the adhesion force for a 20 μm sized oil droplet by more than 400 times from 210 ± 10 to 0.5 ± 0.3 nN as measured by using droplet probe AFM. Finally, we show that silica nanofluids can improve oil recovery rates by 8% in a micromodel with glass channels that resemble a physical rock network.

Polymer Flooding in Heterogeneous Heavy Oil Reservoirs: Experimental and Simulation Studies

Polymer flooding (PF) in heterogeneous heavy oil reservoirs is not only closely related to polymer degradation, but also to non-Newtonian flow. In this paper, both experimental and simulation methods are combined to investigate this type of flooding. Through experiments, the degradation of polymer, rheological properties of fluids, and flow of fluids in porous media were determined. Based on the experimental results, a novel mathematical model was established, and a new PF simulator was designed, validated, and further applied to study the effects of polymer degradation, polymer solution shear thinning, and non-Newtonian flow on PF in heterogeneous heavy oil reservoirs. These experimental results demonstrated that the polymer first-order static degradation rate constant was lower than the polymer first-order dynamic degradation rate constant; the polymer solution and heavy oil were non-Newtonian fluids, with shear thinning and Bingham fluid properties, respectively; and the heavy oil threshold pressure gradient (TPG) in low-permeability porous media was higher than that in high-permeability porous media. All comparison results showed that the designed simulator was highly accurate and reliable, and could well describe both polymer degradation and non-Newtonian flow, with special emphasis on the distinction between polymer static and dynamic degradation and heavy oil TPG. Furthermore, the simulation results verified that polymer degradation, polymer solution shear thinning, and heavy oil TPG all had negative effects on the efficiency of PF in heterogeneous heavy oil reservoirs.

Artificial Neural Network to Forecast Enhanced Oil Recovery Using Hydrolyzed Polyacrylamide in Sandstone and Carbonate Reservoirs

Polymer flooding is an important enhanced oil recovery (EOR) method with high performance which is acceptable and applicable on a field scale but should first be evaluated through lab-scale experiments or simulation tools. Artificial intelligence techniques are strong simulation tools which can be used to evaluate the performance of polymer flooding operation. In this study, the main parameters of polymer flooding were selected as input parameters of models and collected from the literature, including: polymer concentration, salt concentration, rock type, initial oil saturation, porosity, permeability, pore volume flooding, temperature, API gravity, molecular weight of the polymer, and salinity. After that, multilayer perceptron (MLP), radial basis function, and fuzzy neural networks such as the adaptive neuro-fuzzy inference system were adopted to estimate the output EOR performance. The MLP neural network had a very high ability for prediction, with statistical parameters of R² = 0.9990 and RMSE = 0.0002. Therefore, the proposed model can significantly help engineers to select the proper EOR methods and API gravity, salinity, permeability, porosity, and salt concentration have the greatest impact on the polymer flooding performance.

Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability

In recent years, unconventional oils have shown a huge potential for exploitation. Abundant reserves of carbonate asphalt rocks with a high oil content have been found; however, heavy oil and carbonate minerals have a high interaction force, which makes oil-solid separation difficult when using traditional methods. Although previous studies have used nanofluids or surfactant alone to enhance oil recovery, the minerals were sandstones. For carbonate asphalt rocks, there is little research on the synergistic effect of nanofluids and surfactants on heavy oil recovery by hot-water-based extraction. In this study, we used nanofluids and surfactants to enhance oil recovery from carbonate asphalt rocks synergistically based on the HWBE process. In order to explore the synergistic mechanism, the alterations of wettability due to the use of nanofluids and surfactants were studied. Nanofluids alone could render the oil-wet calcite surface hydrophilic, and the resulting increase in hydrophilicity of calcite surfaces treated with different nanofluids followed the order of SiO2 > MgO > TiO2 > ZrO2 > γ-Al2O3. The concentration, salinity, and temperature of nanofluids influenced the oil-wet calcite wettability, and for SiO2 nanofluids, the optimal nanofluid concentration was 0.2 wt%; the optimal salinity was 3 wt%; and the contact angle decreased as the temperature increased. Furthermore, the use of surfactants alone made the oil-wet calcite surface more hydrophilic, according to the following order: sophorolipid (45.9°) > CTAB (49°) > rhamnolipid (53.4°) > TX-100 (58.4°) > SDS (67.5°). The elemental analysis along with AFM and SEM characterization showed that nanoparticles were adsorbed onto the mineral surface, resulting in greater hydrophilicity of the oil-wet calcite surface, and the roughness was related to the wettability. Surfactant molecules could aid in the release of heavy oil from the calcite surface, which exposes the uncovered calcite surface to its surroundings; additionally, some surfactants adsorbed onto the oil-wet calcite surface, and the combined role made the oil-wet calcite surface hydrophilic. In conclusion, the study showed that hybrid nanofluids showed a better effect on wettability alteration, and the use of nanofluids and surfactants together resulted in synergistic alteration of oil-wet calcite surface wettability.

Formulation Improvements in the Applications of Surfactant-Oil-Water Systems Using the HLDN Approach with Extended Surfactant Structure

Soap applications for cleaning and personal care have been used for more than 4000 years, dating back to the pharaonic period, and have widely proliferated with the appearance of synthetic surfactants a century ago. Synthetic surfactants used to make macro-micro-nano-emulsions and foams are used in laundry and detergency, cosmetics and pharmaceuticals, food conditioning, emulsified paints, explosives, enhanced oil recovery, wastewater treatment, etc. The introduction of a multivariable approach such as the normalized hydrophilic–lipophilic deviation (HLD _N) and of specific structures, tailored with an intramolecular extension to increase solubilization (the so-called extended surfactants), makes it possible to improve the results and performance in surfactant–oil–water systems and their applications. This article aims to present an up-to-date overview of extended surfactants. We first present an introduction regarding physicochemical formulation and its relationship with performance. The second part deals with the importance of HLD _N to make a straightforward classification according to the type of surfactants and how formulation parameters can be used to understand the need for an extension of the molecule reach into the oil and water phases. Then, extended surfactant characteristics and strategies to increase performance are outlined. Finally, two specific applications, i.e., drilling fluids and crude oil dewatering, are described.

Polyacrylamide Grafted Xanthan: Microwave-Assisted Synthesis and Rheological Behavior for Polymer Flooding

Application of polymer-flooding systems in secondary and tertiary oil recovery represents a real challenge for oil industry. In this work, our main objective is to explore possibilities of making use of xanthan-g-polyacrylamide for polymer flooding in a particular Devonian oilfield of medium salinity. The graft polymer was synthesized by using microwave-assisted graft copolymerization reaction of acrylamide on xanthan. The synthesized copolymer with optimized grafting parameters has been characterized by Infrared Spectroscopy and Thermal Analysis (DSC). Rheological analysis by steady shear and oscillatory flow experiments have been subsequently performed for xanthan and grafted xanthan under reservoir conditions. In steady shear, as expected the grafted polymer solutions flow as shear-thinning materials and apparent viscosity showed good fits with Cross's model. The viscosity losses due to salinity or temperature are more controlled for the grafted xanthan compared to pristine xanthan. When the grafted polymer concentration is increased to 2000 ppm the losses were halved. In oscillatory shear, the copolymer solutions followed a global behavior of semi-dilute entangled systems; furthermore, all dynamic properties were influenced by the brine salinity. Compared to xanthan, the elastic properties of xanthan-g-polyacrylamide solutions have been significantly improved in saline media and the losses in elasticity of grafted polymer solutions are lower.

The Impact of Rheology on Viscous Oil Displacement by Polymers Analyzed by Pore-Scale Network Modelling

Several experimental studies have shown significant improvement in heavy oil recovery with polymers displaying different types of rheology, and the effect of rheology has been shown to be important. These experimental studies have been designed to investigate why this is so by applying a constant flow rate and the same polymer effective viscosity at this injection rate. The types of rheology studied vary from Newtonian and shear thinning behavior to complex rheology involving shear thinning and thickening behavior. The core flood experiments show a significantly higher oil recovery with polyacrylamide (HPAM), which exhibits shear thinning/thickening behavior compared to biopolymers like Xanthan, which is purely shear thinning. Various reasons for these observed oil recovery results have been conjectured, but, to date, a clear explanation has not been conclusively established. In this paper, we have investigated the theoretical rationale for these results by using a dynamic pore scale network model (DPNM), which can model imbibition processes (water injection) in porous media and also polymer injection. In the DPNM, the polymer rheology can be shear thinning, shear thinning/thickening, or Newtonian (constant viscosity). Thus, the local effective viscosity in a pore within the DPNM depends on the local shear rate in that pore. The predicted results using this DPNM show that the polymer causes changes in the local flow velocity field, which, as might be expected, are different for different rheological models, and the changes in the velocity profile led to local diversion of flow. This, in turn, led to different oil recovery levels in imbibition. However, the critical result is that the DPNM modelling shows exactly the same trend as was observed in the experiments, viz. that the shear thinning/thickening polymer gave the highest oil recovery, followed by the Newtonian Case and the purely shear thinning polymer gave the lowest recover, but this latter case was still above the waterflood result. The DPNM simulations showed that the shear-thinning/thickening polymer show a stabilized frontal velocity and increased oil mobilization, as observed in the experiments. Simulations for the shear-thinning polymer show that, in high-rate bonds, the average viscosity is greatly reduced, and this causes enhanced water fingering compared to the Newtonian polymer case. No other a priori model of the two-phase fluid physics of imbibition, coupled with the polymer rheology, has achieved this degree of predictive explanation, of these experimental observations, to our knowledge.

High Salinity and High Temperature Stable Colloidal Silica Nanoparticles with Wettability Alteration Ability for EOR Applications

The stability of nanoparticles at reservoir conditions is a key for a successful application of nanofluids for any oilfield operations, e.g., enhanced oil recovery (EOR). It has, however, remained a challenge to stabilize nanoparticles under high salinity and high temperature conditions for longer duration (at least months). In this work, we report surface modification of commercial silica nanoparticles by combination of zwitterionic and hydrophilic silanes to improve its stability under high salinity and high temperature conditions. To evaluate thermal stability, static and accelerated stability analyses methods were employed to predict the long-term thermal stability of the nanoparticles in pH range of 4–7. The contact angle measurements were performed on aged sandstone and carbonate rock surfaces to evaluate the ability of the nanoparticles to alter the wettability of the rock surfaces. The results of static stability analysis showed excellent thermal stability in 3.5% NaCl brine and synthetic seawater (SSW) at 60 °C for 1 month. The accelerated stability analysis predicted that the modified nanoparticles could remain stable for at least 6 months. The results of contact angle measurements on neutral-wet Berea, Bentheimer, and Austin Chalk showed that the modified nanoparticles were able to adsorb on these rock surfaces and altered wettability to water-wet. A larger change in contact angle for carbonate surface than in sandstone surface showed that these particles could be more effective in carbonate reservoirs or reservoirs with high carbonate content and help improve oil recovery.