Enhanced Oil Recovery Performance Research Articles

Nanoparticle size: A critical role in enhancing oil recovery

In recent years, nanomaterials have shown great potential in the enhanced oil recovery (EOR) process due to their superior properties. However, the influence of particle size on EOR is not clear and hinders the application. Therefore, it is vitally important to investigate the effect of the particle size on the EOR performance. In this work, Fe3O4 nanoparticles with different sizes, including 20 nm, 100 nm, 200 nm, and 300 nm, were controllably synthesized and used to innovatively clarify the critical role of nanoparticles size in enhancing oil recovery. The effects of sizes on the recovery were investigated by combining the experimental results of interfacial tension, wetting angle, and spontaneous imbibition. The results revealed that Fe3O4 nanoparticles with smaller size, which have the stronger ability to reduce the interfacial tension and change the wetting angle, exhibit a favorable capacity to enhance oil recovery. Compared with the spontaneous imbibition oil recovery (24.36 %) of standard brine, the nanofluid containing 0.1 wt% Fe3O4 with the size of 20 nm can increase the recovery to 30.87 %. Based on the results of nuclear magnetic resonance, the spontaneous imbibition mechanism was proposed and the effect of size on recovery was analyzed. In addition, the superparamagnetism of Fe3O4 was utilized for recycling, avoiding the issue of significant losses of nanofluids in the existing research after injection. The secondary spontaneous imbibition was carried out, showing good environmental friendliness.

Synthesis and Characterization of Self-Dispersion Monodisperse Silica-Based Functional Nanoparticles for Enhanced Oil Recovery (EOR) in Low-Permeability Reservoirs

A controllable particle size mono-dispersing nanofluid system has been developed to address the challenges of low porosity and low-permeability in low to ultra-low-permeability reservoirs. This system combines high dispersion stability with enhanced oil recovery performance, and its effectiveness in improving recovery rates in low-permeability reservoirs, where conventional chemical flooding is ineffective, has been well demonstrated. Using the in situ method to prepare monodispersed nano-silica particles, the effects of the water concentration, ammonia concentration, and silica precursor concentration on the morphology, particle size, and formation time of the silica spherical particles were analyzed. Building on this foundation, a partially hydrophobic modified nano-silica oil displacement fluid was synthesized in situ. The system’s dispersion stability, ability to reduce oil-water interfacial tension, and capacity to alter rock wettability were evaluated. Core physical models were used to evaluate the oil displacement efficiency and the permeability applicability limits of the self-dispersing nano-silica oil displacement system. The experiments confirmed that the particle size distribution of the self-dispersing nano-silica oil displacement system can be controlled within a range of 10 nm to 300 nm. The nanofluids exhibited excellent stability, effectively altering the rock wettability from oil-wet to water-wet and reducing the oil-water interfacial tension to approximately 10−1 mN/m. The nano-displacement system increased the recovery rate of the low permeability reservoirs by more than 17%. The in situ modification method used to prepare these self-dispersing nanoparticles provides valuable insights for synergistic enhancement of recovery when combined with other systems, such as surfactants and CO2. This approach also opens up new possibilities and drives further development in the field of nano-enhanced oil recovery chemistry.

Visualization Experimental Investigation on Flow Regulation and Oil Displacement Characteristics of Gel Foam in Fractured-Vuggy Carbonate Reservoirs.

Fractured-vuggy reservoirs experience severe channeling during water and gas injection operations, and conventional foam shows weak regeneration capabilities in large-scale fracture spaces, thus failing to effectively seal them. Gel foam combines the advantages of both foam and gel, significantly enhancing the foam's stability and showing good suitability in fractured-vuggy reservoirs. In this article, the plugging and flow regulation properties of gel foam in fractures were studied through fracture displacement experiments. The dynamic plugging capability of gel foam was superior to that of ordinary foam, and its plugging effect was significantly influenced by the fracture opening. Gel foam had strong retention capacity in fractures, and after plugging large-opening fractures, the diversion rate of small-opening fractures was increased by at least 83.3 times during subsequent parallel water flooding, making the flow regulation effect remarkable. Through the oil displacement experiments in typical fractured-vuggy models, the profile control law and enhanced oil recovery performance of gel foam under different fractured-vuggy structures were studied. In the regular fractured-vuggy network, gel foam adhered to occupy the fractured-vuggy space for plugging and controlled the top gas migration direction to synergistically drive the recovery of remaining oil, ultimately achieving a recovery of 95%. In the combination of fractures and irregular vugs, due to the density, gel foam continuously pushed down and right along the fractures to the vugs, pushing the crude oil and formation water in the vugs to migrate to the production well. The recovery of the gel foam flooding stage was as high as 48%, and the final recovery reached 93.5; only a small amount of shielded remaining oil was difficult to drive. The research results are of great significance to the application of gel foam in enhancing oil recovery in fractured-vuggy reservoirs.

Predicting and optimizing CO2 foam performance for enhanced oil recovery: A machine learning approach to foam formulation focusing on apparent viscosity and interfacial tension

Carbon dioxide foam injection stands as a promising method for enhanced oil recovery (EOR) and carbon sequestration. However, accurately predicting its efficiency amidst varying operational conditions and reservoir parameters remains a significant challenge for conventional modeling techniques. This study explores the application of machine learning (ML) methodologies to develop a robust model for matching experimental values in CO2 foam flooding scenarios. Leveraging a comprehensive dataset encompassing diverse surfactants and rock types, with varied porosity and permeability, our model demonstrates accurate predictions across a wide spectrum of conditions. By focusing on key parameters such as foam apparent viscosity, interfacial tension (IFT), injected foam volume, initial oil saturation, porosity, and permeability, we unveil the pivotal role of these factors in determining CO2 foam EOR performance. Through rigorous analysis, we identify the relative importance of each input parameter, with injected foam volume, apparent viscosity, and IFT emerging as dominant factors. The most accurate model was deep neural network (DNN) (R2 value of 0.99). Higher foam viscosity and lower IFT were found to significantly enhance oil recovery rates, though their effects plateau beyond certain thresholds (apparent viscosities above 1200 cP and IFT values below 0.2 mN/m). The findings underscore the potential of ML-driven approaches in enhancing CO2 foam EOR predictions, offering insights crucial for optimizing foam flooding performance across diverse reservoir settings.

The conformance control and enhanced oil recovery performance of CO2 foam reinforced by regenerated cellulose

CO2 foam flooding is one of the most promising technologies for conformance control and enhanced oil recovery (EOR) in heterogenous tight oil reservoirs. However, it is challenging to maintain foam stability at in-situ high temperature and high salinity reservoir conditions, thus seriously limiting the flooding efficiency. Herein, a new approach of CO2 foam reinforced by regenerated cellulose (RC) was proposed and evaluated by multiple light scattering method and microscopic detection; afterwards, the conformance control and EOR performances were evaluated via flooding experiments at representative reservoir conditions of 85 °C and 59737.6 mg/L, using artificial micro-models and heterogenous core test. Results have demonstrated that: Compared with CO2 foam without RC, the foam with 1 % RC could elongate the foam half-life by ∼30 times (i.e., from 18 to 543 mins) and the drainage half-time by ∼4 times (i.e., from 2.5 to 9.5 mins), respectively; For the conformance control, the CO2 foam flooding with RC improved the sweep efficiency from the respective 42.4 % and 15.8 % to 95.4 % compared with water flooding and CO2 flooding in the micromodel experiments; the CO2 foam with RC increased the injection pressure from 0.20 to 3.1 MPa in the core flooding experiments, suggesting the diversion of fluid from high permeable to low permeable zone. In terms of the EOR, the CO2 foam flooding with RC improved the oil recovery from the respective 29.7 % and 12.9 % to 92.3 % in contrast with water flooding and CO2 flooding in micro-flooding experiments and from 35.5 % to 56.4 % by core-flooding experiments; the underlying mechanisms are attributed to oil emulsification, rock wettability alteration and foam deformation. These insights provide new approaches to maintain foam stability, improve conformance control and EOR performances in heterogenous tight oil reservoirs under harsh conditions.

Preparation of sodium alginate grafted polyelectrolyte by adiabatic polymerization and study on its solution properties

In order to improve the salt resistance and shear resistance of partially hydrolyzed polyacrylamide-based oil displacement agents (they are all anionic polyelectrolytes), this paper proposes the preparation of branched low hydrophobic monomer content sodium alginate grafted hydrophobically modified partially hydrolyzed polyacrylamide P(AM-SA-MO8) using acrylamide (AM), sodium alginate (SA), and non-ionic hydrophobic monomer (MO8) as main raw materials through the method of adiabatic polymerization followed by hydrolysis. The polymerization conditions of P(AM-SA-MO8) were optimized, and the solution properties and oil displacement performance of P(AM-SA-MO8) and P(AM-MO8) (copolymer of AM and MO8) were compared. It was found that the viscosity, resistance to Ca2+/Mg2+, shear resistance, resistance factor (RF), residual resistance factor (RRF), and enhanced oil recovery performance of P(AM-SA-MO8) solution were better than those of P(AM-MO8). Especially in seawater, at 75 ℃, the viscosity of 1500 mg/L P(AM-SA-MO8) solution was 6.5 mpa.s, RF was 6.08, RRF was 2.28, and the enhanced oil recovery was 26.28 % with a injection rate of 4.9 ft/day.

Research on Inter-Fracture Gas Flooding for Horizontal Wells in Changqing Yuan 284 Tight Oil Reservoir

In tight reservoir development, traditional enhanced oil recovery (EOR) methods are incapable of effectively improving oil recovery in tight reservoirs. Given this, inter-fracture flooding is proposed as a new EOR method, and physical model simulation and numerical simulation are performed for inter-fracture water flooding. Compared with inter-fracture water flooding, inter-fracture gas flooding has a higher application prospect. However, few studies on inter-fracture gas flooding have been reported, and its EOR mechanisms and performance are unclear. This paper used the geological model of the actual tight reservoir to carry out numerical simulations for two horizontal wells in the Changqing Yuan 284 block. The results showed that (1) inter-fracture gas flooding can effectively supplement formation energy and increase formation pressure; (2) inter-fracture gas flooding delivers simultaneous displacement, which can effectively increase the swept area in tight reservoirs; (3) injected CO2 dissolves into the reservoir fluid, reduces fluid viscosity, and improves fluid flow through the reservoir; and (4) the recovery factor increment of the CO2 injection is higher than those of natural gas injection and N2 injection. The findings of this research provide references for the production and development of tight reservoirs.

Investigation of non-chemical CO2 microbubbles for enhanced oil recovery and carbon sequestration in heterogeneous porous media

Non-chemical CO2 microbubble (MB) is a promising environmentally friendly technology for enhanced oil recovery (EOR) and carbon sequestration. Understanding the interaction between non-chemical CO2 MB and oil phases in porous media is crucial for optimizing the design of CO2 MB to enhance both EOR and carbon sequestration efforts. This study explores the impact of oil on the conformance control of non-chemical MB and conducts a case study on their potential for EOR and carbon sequestration in a heterogeneous reservoir. First, experimental results reveal that MB's conformance control is impacted by the presence of oil, with varying degrees of impairment depending on oil composition. Then, reservoir simulations demonstrate that MB outperforms conventional CO2 flooding and water-alternating-gas (WAG), achieving a final recovery of 77.48% of original oil in place compared to 66.79% of original oil in place for CO2 flooding and 68.19% of original oil in place for WAG. Sensitivity analyses highlight the importance of parameters such as gas-liquid ratio of MB, reservoir heterogeneity, and reservoir thickness in MB's EOR performance. Finally, CO2 storage efficiency analyses show that MB exhibits superior CO2 storage efficiency, with higher structural and solubility trapping compared to WAG. The study concludes that MB technology holds promise for EOR and carbon sequestration, contributing to efforts toward carbon neutrality and sustainable oil recovery practices. These findings provide valuable insights for optimizing MB applications in field-scale operations and advancing toward a more environmentally sustainable energy industry.

Study on the mechanism of CO2 huff-n-puff enhanced oil recovery and storage in shale porous media considering heterogeneous structure

CO2 possesses several advantages, including strong solubility, effective viscosity reduction ability, and low miscible pressure, making it a promising candidate for enhanced oil recovery (EOR). Additionally, due to its adsorption capture mechanism, shale formations are considered ideal environments for CO2 storage. However, the influence of heterogeneity of shale multi-scale structure on CO2 migration mechanism, EOR, and storage mechanism is not clear. In this study, a heterogeneous shale structure model containing fractures and matrix was designed based on scanning electron microscope. The multiphase–multicomponent–multirelaxation model was used to study the fluid migration mechanism in the process of miscible CO2 huff-n-puff in shale reservoir. By analyzing density variations, velocity changes, and pressure distributions, the effects of diffusion coefficient, adsorption parameters, and fracture size were studied. Furthermore, by changing the matrix structure, the influence of heterogeneity on the law of oil and gas migration was explored. Additionally, a comparison between CO2 and water was performed. Finally, the influence of reservoir heterogeneity on fluid transport mechanism was studied. The results show that EOR and CO2 storage rate (CSR) are proportional to the diffusion coefficient. The main factor affecting the CSR is the adsorption capacity of rock to CO2. The larger CO2–oil contact area between the fracture and the matrix leads to a larger CSR, highlighting the importance of induced fractures. In addition, it was found that CO2 huff-n-puff was superior to water flooding, showing an EOR performance advantage of about 15%. This study is helpful for the practical application of CO2 huff-n-puff technology in the field of unconventional oil and gas development and CO2 storage.

Forecasting the efficiency of waterflooding, thermal and chemical enhanced oil recovery methods in Bobrikovian reservoirs

The development of reserves contained viscous and highly viscous oil poses one of the major challenges in modern reservoir engineering. The poor performance of conventional waterflooding prompts the application of enhanced oil recovery (EOR) methods, of which thermal and chemical EOR are considered the most efficient. Reservoir simulation is a powerful tool for evaluating EOR performance. Serial runs of a history-matched model of a Bobrikovian reservoir are used to evaluate the incremental oil production due to each EOR technique and formulate the efficiency limits of the process performance criteria. In contrast to previous studies that evaluated EOR applications using reservoir simulation modeling, an entirely new quality model is derived through automatic history matching performed by solving an inverse problem. Another novel feature is the automated selection of the optimum field development scenario given a user-defined objective function. Evaluating the performance of hot water injection in a Bobrikovian reservoir suggests that this technology yields positive effects when the injected water temperature ranges from 50 °C to 90 °C. The surfactant–polymer flooding method is also investigated. The largest incremental oil production with a constant surfactant concentration of 0.5% is observed for a polyacrylamide concentration of 0.25%, which can be attributed to a water cut reduction due to plugging the well-drained and flushed reservoir zones. The greatest incremental oil production is achieved when injecting 1.5% surfactant and 0.25% polyacrylamide. The highest efficiency per ton of injected chemicals is obtained when injecting 0.5% polyacrylamide and 0.10% surfactant. Keywords: High-viscosity oil; EOR; thermal methods; surfactant-polymer flooding; reservoir simulation; history matching; injection simulation scenario.

Evaluation of the Thermal, Chemical, Mechanical, and Microbial Stability of New Nanohybrids Based on Carboxymethyl-Scleroglucan and Silica Nanoparticles for EOR Applications.

Scleroglucan (SG) is resistant to harsh reservoir conditions such as high temperature, high shear stresses, and the presence of chemical substances. However, it is susceptible to biological degradation because bacteria use SG as a source of energy and carbon. All degradation effects lead to viscosity loss of the SG solutions, affecting their performance as an enhanced oil recovery (EOR) polymer. Recent studies have shown that nanoparticles (NPs) can mitigate these degradative effects. For this reason, the EOR performance of two new nanohybrids (NH-A and NH-B) based on carboxymethyl-scleroglucan and amino-functionalized silica nanoparticles was studied. The susceptibility of these products to chemical, mechanical, and thermal degradation was evaluated following standard procedures (API RP 63), and the microbial degradation was assessed under reservoir-relevant conditions (1311 ppm and 100 °C) using a bottle test system. The results showed that the chemical reactions for the nanohybrids obtained modified the SG triple helix configuration, impacting its viscosifying power. However, the nanohybrid solutions retained their viscosity during thermal, mechanical, and chemical degradation experiments due to the formation of a tridimensional network between the nanoparticles (NPs) and the SG. Also, NH-A and NH-B solutions exhibited bacterial control because of steric hindrances caused by nanoparticle modifications to SG. This prevents extracellular glucanases from recognizing the site of catalysis, limiting free glucose availability and generating cell death due to substrate depletion. This study provides insights into the performance of these nanohybrids and promotes their application in reservoirs with harsh conditions.

Influence of viscosity ratio on enhanced oil recovery performance of anti-hydrolyzed polymer for high-temperature and high-salinity reservoir

The viscosity ratio of polymer and oil is a crucial factor for polymer flooding, which can affect the water–oil mobility ratio and oil recovery. However, for high-temperature and high-salinity reservoirs, the reasonable viscosity ratio limit of polymer flooding under the condition of medium–high permeability and low oil viscosity is not clear. Thus, the heterogeneous sand-pack flooding experiments were carried out to analyze the influence of polymer–oil viscosity ratio on the enhanced oil recovery (EOR) performance of anti-hydrolyzed polymer to establish a reasonable viscosity ratio limit. Then the three-dimensional heterogeneous model flooding experiments were performed to clarify the mechanism. The results showed that when the permeability ratio was the same, as the viscosity ratio increased from 0.15 to 2.0, the incremental oil recovery increased from 3.2% to 27.2%. When the viscosity ratio was the same, the incremental oil recovery decreased with the increase in the permeability ratio. The reasonable viscosity ratio ranges from 1.0 to 1.5. For three-dimensional heterogeneous model flooding experiments, as the polymer–oil viscosity ratio increased from 0.45 to 1.0, the swept area of high and low permeability area was expanded and the oil saturation near the injection well in the mainstream channel was greatly reduced. Moreover, when the polymer–oil viscosity ratio was 1, the difference in the width of the mainstream channels between high and low permeability layers in the saturation field decreased, and the degree of utilization in low permeability layers increased significantly. As the polymer–oil viscosity ratio increased from 0.45 to 1.0, the incremental oil recovery increased from 16.2% to 24%.

Development and performance evaluation of nonionic surfactant-stabilized nanoemulsion for enhanced oil recovery applications in tight reservoir

Nanoemulsions have garnered great attention as a chemical additive for enhanced oil recovery (EOR) technology worldwide due to their small size and unique physicochemical properties. Herein, this work introduces a novel nonionic surfactant-stabilized nanoemulsion prepared using a low-energy method for EOR projects in the Chang 8 tight reservoir. Spontaneous imbibition experiments were conducted in oil-saturated cores, and secondary imbibition experiments were carried out in water-bearing cores. Additionally, core flooding experiments were performed to study the EOR performance of both nanoemulsion and complex surfactant. Finally, the EOR mechanisms were thoroughly investigated, specifically focusing on oil-washing capacity, reduced interfacial tension, and wettability alteration. The designed nanoemulsion, with droplets averaging 10.5 ± 0.7 nm in synthetic formation brine at ambient temperature, exhibits excellent thermal and long-term stability even under reservoir temperature conditions. The oil recovery efficiency of the nanoemulsion system in oil-saturated cores through spontaneous imbibition was 31.28%, representing a 6.42% improvement over the complex surfactant solution. In the secondary imbibition experiments, the nanoemulsion mobilized 8.53% of the residual oil, compared to 4.11% for the complex surfactant. Core flooding experiments revealed that the nanoemulsion system achieved a total oil recovery of 62.69%, outperforming the complex surfactant system by 8.68% during the chemical flooding stage and 1.82% during the subsequent brine flooding stage. The EOR mechanisms of nanoemulsion in tight reservoirs can be attributed to four aspects: reduction of oil/water interfacial tension, wettability alteration, miscibility with crude oil, and increased sweep volume. The generation of the Marangoni effect and the adsorption and diffusion characteristics are essential differences between the nanoemulsion system and the complex surfactant system. The presented findings in this paper could aid in promoting the large-scale use of nanoemulsions in Chang 8 tight reservoirs.

Development of Novel Silicon Quantum Dots and Their Potential in Improving the Enhanced Oil Recovery of HPAM.

Hydrolyzed polyacrylamide (HPAM) is commonly used in polymer flooding, however, it is prone to viscosity reduction at high temperatures and high salinities, weakening its ability to improve oil recovery. In this work, sulfonated modified silicon quantum dots (S-SiQDs) were synthesized and then added to HPAM to study the improvement of rheological properties and enhanced oil recovery performance of HPAM at high temperatures and salinities. It is found that the S-SiQDs with a concentration of only 0.1 wt % can significantly increase the viscosity of HPAM from 28.5 to 39.6 mPa·s at 60 °C and 10,000 mg/L NaCl. Meanwhile, the HPAM/S-SiQDs hybrid solution always possessed higher viscosity and viscoelastic moduli than HPAM, attributed to the hydrogen bonding between HPAM and S-SiQDs. Notably, HPAM/S-SiQDs still maintained elastic behavior at harsh conditions, indicating that they formed a strong network structure. Through oil displacement experiments, it was found that the oil recovery of HPAM/S-SiQDs was higher (28.3%), while that of HPAM was only 17.2%. Thereafter, the utilization sequence of oil during the displacement process was studied with nuclear magnetic resonance experiments. Ultimately, the oil displacement mechanism of HPAM/S-SiQDs was deeply analyzed, including viscosity thickening and wetting reversal.

A review of mechanisms influencing stable rheology complex Pickering foams for carbon utilization & storage in subsurface formations

While CO2 foams have been utilized for tertiary oil recovery and carbon collection, utilization, and storage for quite some time, but due to foam instability, the storage efficiency and enhanced oil recovery (EOR) of this method have been less efficient. Pickering foam represents a complex fluid made of CO2 bubbles stabilized by nanoparticles in water (NPs). This approach considerably enhances EOR and CO2 storage performance. The various mechanisms influencing the stabilization of a foam by an NPs have also been discussed. As a CO2 foam enhancer, NPs improve the foam layer & interfacial dilatational viscoelasticity and dynamic CO2 storage. Incorporating NPs on the foam lamella inhibits foam bubble disintegration and enhances foam’s durability. The novelty of the work lies in the concise explanation of various mechanisms influencing the success of Pickering foams in this role. A stable CO2 foam when injected into a heterogeneous porous media causes a larger areal sweep, even under adverse shear conditions and regains initial rheological profile, once shear is withdrawn, and the improved CO2 storage contributed to a boost in sweep efficiency, enabling the collection of larger amounts of oil.

Experimental investigation into effects of the natural polymer and nanoclay particles on the EOR performance of chemical flooding in carbonate reservoirs

This paper aims to investigate the tragacanth gum potential as a natural polymer combined with natural clay mineral (montmorillonite, kaolinite, and illite) nanoparticles (NPs) to form NP–polymer suspension for enhanced oil recovery (EOR) in carbonate reservoirs. Thermal gravimetric analysis (TGA) tests were conducted initially in order to evaluate the properties of tragacanth gum. Subsequently, scanning electron microscopy (SEM) and energy-dispersive X-ray (EDX) tests were used to detect the structure of clay particles. In various scenarios, the effects of natural NPs and polymer on the wettability alteration, interfacial tension (IFT) reduction, viscosity improvement, and oil recovery were investigated through contact angle system, ring method, AntonPaar viscometer, and core flooding tests, respectively. The entire experiment was conducted at 25, 50, and 75 °C, respectively. According to the experimental results, the clay minerals alone did not have a significant effect on viscosity, but the addition of minerals to the polymer solution leads to the viscosity enhancement remarkably, resulting mobility ratio improvement. Among clay NPs, the combination of natural polymer and kaolinite results in increased viscosity at all temperatures. Considerable wettability alteration was also observed in the case of natural polymer and illite NPs. Illite in combination with natural polymer showed an ability in reducing IFT. Finally, the results of displacement experiments revealed that the combination of natural polymer and kaolinite could be the best option for EOR due to its substantial ability to improve the recovery factor.

Zwitterionic-nonionic compound surfactant system with low chromatographic separation effect for enhanced oil recovery

Ultra-low oil/water interfacial tension (IFT) is an important parameter for evaluating the enhanced oil recovery performance of surfactant flooding. It is difficult to achieve ultra-low interfacial tension with crude oil by a single surfactant, so compound system is often used. However, the chromatographic separation effect of each component in the compound system will severely affect the practical oil displacement performance. In this study, a novel compound oil displacement system was prepared by a zwitterionic surfactant (oleic amidopropyl betaine, OAB) and a nonionic surfactant (coconut oil diethanolamide, CDEA) at a mass ratio of 1:1. The capability of reducing IFT, emulsification, wettability reversal and oil film peeling performance of this system were evaluated. The results show that by promoting the dense arrangement of surfactants at the oil/water interface and realizing hydrophilic-lipophilic balance, the OAB-CDEA compound system can reduce the IFT to 10−4 mN/m. The system also exhibits excellent emulsification performance, and when placed at undisturbed state, the small and uniform emulsion droplets demulsify spontaneously and completely within 3 h. The compound system can regulate the wettability of rock surface from oleophilic to strongly hydrophilic, increasing the underwater oil contact angle from 24° to 157°. Based on the static oil film peeling tests, the oil film reduction rate can reach 88%. Using a 0.3% compound system for the core flooding tests, a recovery up to 75% can be attained, which is ∼30% higher than that of simulated formation water flooding. Meanwhile, the system exhibits low chromatographic separation effect, with chromatographic separation factor Foc close to 1. The OAB-CDEA compound system proposed in this work demonstrates excellent oil displacement performance as well as low chromatographic separation effect, exhibiting great potential in oilfield practical application.

A viscosity study of charcoal-based nanofluids towards enhanced oil recovery

Research into nanofluids for enhanced oil recovery (EOR) has been carried out for more than a decade. Metal oxide nanoparticles dispersed in water are usually applied and the nanofluids can recover 8–16 % more of the original oil in place after or comparing to water flooding, while the oil recovery capacity of carbon tube nanofluids can be even better. Higher viscosities of nanofluids than that of water are one of the key properties that contribute to their good performance in EOR. This work, for the first time, prepared nanofluids from two charcoal samples as well as an active carbon sample for their possible application for EOR. The relationship of nanofluid viscosities with pH values as well as nanoparticle concentrations of the nanofluids was studied for their viscous behaviour in different shear conditions. Their representative viscosity data measured at 100 rpm were examined for the values of the so-called Dispersion Factor (DF). The determined DF values for the charcoal-based nanofluids are close to those of metal oxide nanofluids that have much smaller nanoparticle sizes. The highly porous active carbon nanofluid showed strong viscosity enhancement that is comparable to the values reported for nanofluids of carbon nanotubes. Due to their significant viscosity enhancement and carbon sequestration feature, the charcoal-based nanofluids are promising to be used for EOR.

Novel Anionic-Nonionic Surfactant Based on Water-Solid Interfacial Wettability Control for Residual Oil Development.

Irreversible colloidal asphaltene adsorption layers are formed on formation rock surfaces due to long-term contact with crude oil, and large amounts of crude oil adhere to these oil-wet layers to form residual oil films. This oil film is difficult to peel off due to the strong oil-solid interface effect, which seriously restricts further improvement in oil recovery. In this paper, the novel anionic-nonionic surfactant sodium laurate ethanolamide sulfonate (HLDEA) exhibiting strong wetting control was synthesized by introducing sulfonic acid groups into the nonionic surfactant laurate diethanolamide (LDEA) molecule through the Williamson etherification reaction. The introduction of the sulfonic acid groups greatly improved the salt tolerance and the absolute value of the zeta potential of the sand particles. The experimental results showed that HLDEA altered the wettability of the rock surface from oleophilic to strongly hydrophilic, and the underwater contact angle increased substantially from 54.7 to 155.9°. In addition, compared with LDEA, HLDEA exhibited excellent salt tolerance and enhanced oil recovery performance (the oil recovery was improved by 19.24% at 2.6 × 104 mg/L salinity). Based on nanomechanical experimental results, HLDEA was efficiently adsorbed on the core surfaces and regulated microwetting. Moreover, HLDEA effectively reduced the adhesion force between the alkane chains and the core surface, which facilitated residual oil stripping and oil displacement. This new anionic-nonionic surfactant affording great oil-solid interface wetting control has practical significance for the efficient development of residual oil.

Adaptability and enhanced oil recovery performance of surfactant–polymer flooding in inverted seven-spot well pattern

As one of the leading technologies for chemical enhanced oil recovery (cEOR), surfactant–polymer (SP) flooding technology has long attracted the interest of petroleum scientists and engineers. However, most of its application scenarios are based on the five-spot well pattern. The EOR potential in an inverted seven-spot well pattern is seldom ever recorded. The applicability of the SP system in the inverted seven-spot well pattern was examined based on the physical characteristics of Karamay Oilfield in China. The numerical simulation and the one-dimensional core flooding experiment were used to compare the sweep intensities and EOR abilities of the two well patterns. The migration law and the EOR ability of the SP system were assessed by a specially made one-third inverted seven-spot configuration. The main controlling factors and compatibility charts of SP flooding development in the inverted seven-spot well pattern were obtained. Results show that 61% of the region is represented by a weak swept state in the inverted seven-spot well pattern. The effective swept area is greatly increased by appropriately raising the viscosity and slug size of the SP system. Compared to constant viscosity injection, step-down viscosity injection further increases the sweep range and oil recovery. The inverted seven-spot well pattern has a greater swept area of the SP system than the five-spot one, but a weaker strength. Polymer concentration is the most effective factor of SP flooding in the inverted seven-spot well pattern, followed by oil viscosity and surfactant concentration. The study can broaden the application of the SP system in the inverted seven-spot well pattern.