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Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant–polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant–polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant–polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant–polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant–polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Recently, much attention has been directed toward nanofluids' applications for enhanced oil recovery (EOR). Here, amphiphilic molybdenum disulfide (KH550-MoS2) nanosheets are synthesized using a hydrothermal approach. The physicochemical properties and EOR potential of ultralow concentration KH550-MoS2 nanofluids are systematically investigated at Changqing Oilfield (China) reservoir conditions (temperature∼55 °C and salinity∼7.8 × 104 mg/L). Interfacial tension (IFT), wettability alteration and emulsion stability are characterized to evaluate the physicochemical properties of KH550-MoS2 nanofluids. The results show that ultralow concentration KH550-MoS2 nanofluid (50 mg/L) can decrease IFT to 2.6 mN/m, change contact angle (CTA) from 131.2° to 51.7° and significantly enhance emulsion stability. Core flooding experiments are conducted to determine the dynamic adsorption loss law and oil displacement efficiency of KH550-MoS2 nanofluid. Results indicate that the cumulative produced KH550-MoS2 nanosheets ratio to total injected KH550-MoS2 nanosheets (CNR) reaches 91.5% during flooding in a low permeability reservoir. Moreover, ultralow concentration KH550-MoS2 nanofluid can increase oil displacement efficiency by 14% after water driven. This work offers a new amphiphilic nanofluid with high efficiency for EOR. [ABSTRACT FROM AUTHOR]

The carbon dioxide (CO2) injection is the promising enhanced oil recovery technique used in low permeability reservoirs. The presence of high permeability fractures along the matrix leads to poor sweep efficiency and gas channeling effect. The CO2 responsive mobility control gels could be a potential solution to mitigate the gas channeling effects. This work showcases the straightforward method to prepare a CO2 responsive gel by mixing aqueous suspension of nanocellulose and ethylenediamine. The addition of CO2 leads to protonation of amine which enhances the ionic strength of the solution. This promotes the agglomeration of nanocellulose to form gel. The rheological properties of the gel were studied and found to have interesting mechanical property. And the micromodel is used to visualize the mobility control phenomenon of the as prepared gel. The core flooding experiment proves that the synthesized gels were effective in low permeable cores. [ABSTRACT FROM AUTHOR]

Foam-assisted steam flooding is a promising technique to alleviate gas channeling and enhance sweep efficiency in heterogeneous heavy-oil reservoirs. However, long-term foam stabilization remains problematic at high temperatures. Three-phase foam (TPF), containing dispersed solid particles, has been proposed to improve foam stability under harsh reservoir conditions. We fabricated a novel TPF system by adding ultrafine fly ash particles, as well as high-temperature resistant microspheres with an adhesive coating layer. This work aims at assessing the ability of the generated TPF in controlling steam channeling and enhancing oil recovery. Static and core flood tests were performed to evaluate foam strength and stability. Our results suggested a stronger foamability at a lower consolidation agent concentration, while a longer half-life period of foam and settling time of solid particles at a larger consolidation agent concentration were observed. Bubbles suspended independently in the liquid phase, with sizes varying from 10 to 100 μm, smaller than that of the conventional foam, suggesting a significant enhancement of foam dispersity and stability. The plugging rate was close to 90% when the temperature was as high as 300 °C, demonstrating a well-accepted plugging effect under high temperatures. A larger pore volume injection of TPF yielded a higher EOR in parallel cores, which substantiated the effectiveness of the three-phase foam system in sealing high-permeability channels. [ABSTRACT FROM AUTHOR]

Gemini surfactants have attracted intensive attention owning to their unique physical and chemical properties and have gradually been applied in the field of enhanced oil recovery (EOR). In this work, a combined cationic/anionic-nonionic gemini surfactant system consisting of cetyltrimethyl ammonium bromide (CTAB) and anionic-nonionic gemini surfactants (GAES-9) was proposed for EOR. The surface performance of the combined system was superior to that of either surfactant alone. Critical micelle concentration (CMC) data were used to calculate the molecular interaction parameters according to the regular solution theory. The combined CTAB/GAES-9 surfactant system could greatly affect the interfacial tension (IFT) between water and crude oil, and the strength of this effect depended on the mole fraction and concentration of CTAB/GAES-9. The system could reduce the IFT to an ultra-low level at a total concentration of 200 mg/L, and the system could still maintain ultra-low IFT at a salinity of 10 × 10 4 mg/L. The mechanism underlying the synergistic effect of CTAB/GAES-9 to obtain ultra-low IFT was systematically investigated. It is most probably related to a large number of anions and cations being adsorbed onto the oil-water interface due to electrostatic attraction. Meanwhile, the spatial structure of the elongated, flexible EO chains in the gemini surfactant entangled at the oil-water interface shields some CTAB cations, enabling the adsorption of more cations. To summarize, the combined surfactants exhibit remarkable abilities and could serve as a candidate for EOR in harsh reservoirs. [ABSTRACT FROM AUTHOR]

Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs. [ABSTRACT FROM AUTHOR]

An acid-alternating-base (AAB) system was evaluated based on ability to generate CO 2 in a reservoir for blockage removal and oil recovery improvement. CO 2 generation processes were measured in both the containers and the porous media for comparison. Optimal CO 2 production and generating efficiency were obtained by adjusting the acid molar concentration ratio and system mass concentration. The AAB system had a good displacement efficiency in both homogeneous and heterogeneous porous media. Enhanced oil recovery (EOR) mechanisms of the acid-alternating-base (AAB) technology were then investigated. The basic solution of the AAB system can lower interfacial tension (IFT) between crude oil and displacing fluid; the CO 2 generated in formation can swell oil and reduce oil viscosity; the heat released by the acid-base reaction can dissolve organics and increase oil recovery, and the pressure fluctuation caused by CO 2 generation process and inorganic dissolution can also contribute to the improvement of oil recovery. This technology has been successfully applied in the offshore Bohai Bay Field approximately 200 km east of Beijing. [ABSTRACT FROM AUTHOR]

Multi-scale fractures and karst caves are the main reservoir bodies in fractured-vuggy carbonate reservoirs, and there are still various types of remaining oil after water flooding. Oilfield development practices demonstrate that the method of N 2 injection can enhance oil recovery effectively. However, the development effect of a single well with gas injection is highly different, and the mechanism and influencing factors of gas injection for enhanced oil recovery are not clear. To reveal the mechanism and influencing factors of enhanced oil recovery through physical experiments and numerical simulation, we have produced a series of physical models of fracture and cave combinations based on the characteristics of this type of reservoir, established a visual physical simulation experimental apparatus and process, and analyzed the main factors affecting the production efficiency of gas injection wells in combination with the actual development of oilfields. The research results demonstrate that the primary types of remaining oil after water flooding in fractured-vuggy carbonate reservoirs are oil at the top of karst caves, oil shielded from high flow channels and oil not swept by the wells. The mechanism of gas injection-enhanced oil recovery is primarily composed of three aspects. First, the injected gas forms a secondary gas cap because of the effect of gravitational differentiation, and the gas cap can displace the remaining oil on top of the karst cave that the injected water cannot drive; Then, injected gas can change the pressure field distribution and the direction of fluid flow after water injection, driving the remaining oil that is shielded by high flow diversion channels; in addition, the injected gas has a certain effect on the reservoir energy supply. The geological conditions, such as the remaining reserves of injecting gas wells, filling level, well-reservoir position relationship and bottom water energy, have great influence on the development effect. The starting time of gas injection has an optimal point, and injecting too early or late will affect the oil recovery. The cyclic gas injection quantity and gas injection velocity are the primary injection production parameters that influence the production effect of a gas injection well. Finally, the principle of selecting a well for gas injection according to the research results is discussed, which can provide reference for selecting gas injection wells and injection methods of fractured-vuggy reservoirs in Tahe Oilfield. [ABSTRACT FROM AUTHOR]

The major objective of this paper was to evaluate the validity of in-situ CO 2 generation technique as an enhanced oil recovery method in sandstone reservoirs. In this study, the endothermic decomposition of ammonium bicarbonate solution was used to generate CO 2 . The theoretical prediction model of generated CO 2 volume under reservoir conditions was deduced from the reaction kinetics. It was verified by the experimental data from gas-forming reaction test. The results indicated that the prediction based on the established theoretical model was well matched to experimental results at the tested NH 4 HCO 3 concentrations of 10, 15, 20 wt%. The oil displacement efficiency of in-situ CO 2 generation huff-n-puff (ISCGHP) were further examined through both sandpack test and reservoir simulation. The gas-forming agent was composed of ammonium bicarbonate, surfactants and polymers. The displacement performance of ISCGHP was examined through the sandpack huff-n-puff test. Effects of the main injection parameters were analyzed, including concentration, slug size, injection mode and chasing water. The sandpack huff-n-puff test indicated that a higher concentration of NH 4 HCO 3 and a larger slug size of reagent contributed to an improved oil displacement efficiency. Gradually increasing the slug size reached the remaining oil left in the previous cycle, and simultaneously enlarged swept volume in the following cycle. In the numerical study, the reservoir model of ISCGHP was established using data from interfacial tension test, PVT test and reaction kinetics. It was then calibrated based on sandpack test results and past production observations of the candidate-well. Results showed ISCGHP effectively improved single-well productivity with a growth rate of 56% in oil production, the effective sweep radius reached about 50 m away from the wellbore along with a slight fall of formation temperature and a maximal 22.8% of oil viscosity reduction. [ABSTRACT FROM AUTHOR]

The 4th block Ordovician fractured-cavity carbonate reservoir of Tahe oil-field consists of high-density fractures and large caves which are well developed. The oil is stored in fractures and caves, rather than carbonate rock matrix. In other words, the carbonate rock matrix has no oil storage capability and permeability is extremely low. The fractured-cavity carbonate reservoir possesses the features of severe heterogeneity, complex structure of reservoir space. During the development, many shortcomings such as short period of stable production, early water breakthrough, fast increasing of water cut, high natural decline rate and low degree of development are exposed gradually. The well which cannot achieve effectiveness by water injection was selected to carry out N 2 flooding experiments in Tahe oil-field. By the end of September 2012, the total injection volume of high pressure N 2 was 700 m 3 and the incremental oil production was 2600 t. However the displacement mechanism was still poorly understood. In this paper, a two-dimensional visual fractured-cavity carbonate reservoir model was developed based on the distribution feature, space structure and connection type of fractures and caves in reservoir space. Four main types of residual oil i.e., attic oil, locked oil, bypassed oil and residual oil trapped in the filled area were determined from the water flooding experiments. Also, their formation mechanism was investigated. In addition, the recovering mechanism of residual oil was clarified on the basis of N 2 flooding experiments. The results show that N 2 flooding can significantly increase the oil recovery by more than 40% after water flooding, and it mainly mobilized attic oil and partial locked oil. The entire experiment process was recorded by video, therefore the displacing process of residual oil can be observed directly. These results in this study indicate that N 2 flooding has a broad application prospect in fractured-cavity carbonate reservoir. [ABSTRACT FROM AUTHOR]

The objective of this paper is to investigate an oil-tolerant foam system as a displacing agent to improve the efficiency of oil recovery. To achieve this objective, several foaming agents are examined based on foam–oil interaction models and previous studies. By measuring the interfacial and surface tensions of surfactants, we investigate the implications of the value of spreading coefficient and the lamella number in a system of foaming agents. The foamability and foam stability of the preferred foaming agents were statically tested. At last, the oil tolerance of the foaming agent system in both static and core flow experiments was investigated. Results indicated that the oil tolerant foaming system performs best among the various surfactants tested. In static testing, both foamability and foam stability increase as concentrations of surfactant and salt increase. It was also observed that the polymer significantly increases the foam stability in the presence of oil. The oil droplets do not spread at the surface due to the properties of the oil-tolerant foam, so the foam can be stable in the presence of crude oil. The oil tolerant foaming system exhibits much greater foaming volume and longer drainage-half time than ordinary foam, either in the presence or absence of oil. The mobility reduction factor for dynamic displacement of oil-tolerant foam is much higher than those of pure foam and polymer solutions in the presence of oil. Experiments with different remaining oil saturations reveal that when the residual oil saturation is about 40%, the oil-tolerant foam can achieve the highest oil recovery. [ABSTRACT FROM AUTHOR]

[Display omitted] • Morphology of modified MoS 2 nanosheets adsorbed at W/O interface is obtained by MD. • The stress exerted on a nanosheet is analyzed. • The non-uniform forces acting on a nanosheet result in an intersection angle. • Notable IFT decline is followed by fluctuation with increased nanosheet concentration. • Competition between interface coverage and intersection angle causes IFT fluctuation. Plate-shaped nanoparticles exhibit huge potential for a broad range of cutting-edge applications in interfacial-based science and technology, such as enhanced oil recovery in hydrocarbon reservoirs, owing to their remarkable features in superior affinity toward interfaces. Understanding the adsorption behavior of nanosheets (NSs) self-assembled at the water/oil interface (W/O interface) is crucial to elucidate the variation of interfacial tension (IFT) and establish special design criteria for efficient industrial use of NSs. Here we present a molecular dynamics study to reveal the morphology of carbon-chain modified molybdenum disulfide (MoS 2) nanosheets. The stress exerted on a nanosheet is analyzed. The simulation results demonstrate a significant decrease in interfacial tension after adding NSs to the water/oil system, followed by a noticeable fluctuation with increased NS concentration. Surprisingly, the carbon-chain modified MoS 2 nanosheets do not show a greater ability in altering IFT compared to unmodified ones. The IFT fluctuation is found strongly linked to the competition between the effects of interface coverage rate of adsorbed nanosheets and the intersection angle arising from non-uniform forces acting on a nanosheet. [ABSTRACT FROM AUTHOR]

With the gradual declining of oil increment performance of CO2 huff-and-puff wells, the overall oil exchange rate shows a downward tendency. In this regard, CO2 synergistic huff-and-puff technologies have been proposed to maintain the excellent effect and extend the technical life of such wells. However, there is no specific research on the mechanism and synergistic mode of CO2 huff and puff in horizontal wells. This study aims to establish the synergistic mode and determine the adaptability and acting mechanism of CO2 synergistic huff and puff. Three synergistic huff-and-puff modes are proposed based on the peculiarity of the fault-block reservoir's small oil-bearing area and broken geological structure. We establish three typical CO2 synergistic huff-and-puff models and analyze the influence of different geological and development factors on the huff-and-puff performance with numerical simulation. Each factor's sensitivity is clarified, and the enhanced oil recovery (EOR) mechanism of CO2 synergistic huff and puff is proposed. The sensitivity evaluation results show that the reservoir rhythm, inter-well passage, well spacing, high-position well liquid production rate, and middle-well liquid production rate are extremely sensitive factors; the stratum dip and injection volume allocation scheme are sensitive factors; and the relationship with structural isobaths is insensitive. The EOR mechanism of synergistic huff and puff includes gravity differentiation, supplementary formation energy, CO2 forming foam flooding, and coupling effect of production rate and oil reservoirs. The implementation conditions of the two-well cooperative stimulation mode are the simplest. The two-well model is suitable for thick oil layers with a positive rhythm and large formation dip. The single-well mode requires no channeling between the wells, and the multi-well mode requires multi-well rows and can control the intermediate well's fluid production rate. Field application at C2X1 block shows a good performance with a total oil increment of 1280 t and an average water-cut reduction of 57.7%. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoir played a significant role in unconventional reservoirs, but it was difficult to be developed due to its complex reservoir types. Therefore, it was crucial to find a suitable development program to enhance oil recovery. In this work, a two-dimensional visual physical model of fractured-vuggy reservoir was designed and fabricated according to actual geological data and injection-production characteristics of a representative fractured-vuggy carbonate reservoir, Tahe Oilfield in China. Nitrogen flooding experiment, nitrogen flooding under the high gas energy experiment, nitrogen flooding under strong bottom water energy experiment and foam assisted nitrogen gas flooding experiment were carried out respectively by using two-dimensional visual model. The flow behaviors and the main mechanisms for enhanced oil recovery were revealed by analyzing the oil displacement performance in the visual physical model. Experiment results showed that the gas cap energy and the bottom water energy played a synergistic effect in the nitrogen flooding. The stronger the bottom water energy was, the larger the gas spread area was, and the increase of oil recovery would be very high. If the gas injection rate was too strong, the dominant gas flow channel would be formed prematurely, and the oil recovery was little increase. In addition, foam could effectively control the gas mobility, delay the formation of gas channeling. Meanwhile, the oil recovery of foam assisted nitrogen gas flooding was higher 12% than that of nitrogen flooding. Therefore, the mechanism for improving the degree of development was obtained mainly through gravity differentiation to form the secondary gas top and realize the development of the remaining oil. • A two-dimensional visual physical model of fractured-vuggy reservoir was designed and fabricated. • The flow behaviors and the main mechanisms for nitrogen and foam assisted nitrogen gas flooding were studied. • The oil recovery of foam assisted nitrogen gas flooding was higher 12% than that of nitrogen flooding. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoirs are becoming the key to oil reserves, but their complex reservoir structure and connectivity make it difficult to be developed. In this work, a visual physical model representing an underground river reservoir in two-dimensional fractured-vuggy reservoir was designed and fabricated to study gas channeling characteristics of nitrogen and foam flooding. In order to further study the influence of the porous media on gas channeling characteristics of foam and nitrogen gas flooding, the visual physical model was filled with 2 mm transparent glass beads and the effects of glass beads on different types of nitrogen and foam flooding gas channeling were studied. Experimental results showed that the synergistic action of gas and water and the bottom water energy were the important factors affected gas channeling. Furthermore, foam could effectively control gas mobility, delay formation of gas channeling. In terms of enhanced oil recovery, the recovery efficiency of foam flooding was 35% higher than nitrogen flooding in the horizontal model. In addition, the glass beads in fractured-vuggy of underground river reservoirs could change the flow direction of the fluid and cause a certain flow resistance, foam was more easily to occur gas channeling in the longitudinal model filled with glass beads. The oil recovery by foam in the longitudinal model filled with glass beads was lower 12% than that in the longitudinal model. Therefore, determined the factors that influence gas channeling had a practical value for enhancing oil recovery in fractured-vuggy reservoirs. • Designed and fabricated two-dimensional visual physical model of fracture-vuggy reservoir. • The main control factors affected gas channeling were determined. • Foam could effectively control gas mobility, delay formation time of gas channeling and improve oil recovery. [ABSTRACT FROM AUTHOR]

Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using α-starch, acrylamide, N,N′-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T 90 as indicators at temperature of 30–120 °C, salinity of 0–240 g/L and oil percentage of 0–50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery. [ABSTRACT FROM AUTHOR]

Nitrogen gas drive and foam drive are commonly adopted for practical production in fractured carbonate reservoirs. A systematic study on nitrogen gas drive and foam assisted nitrogen gas drive in varying-aperture fractures is a practical and essential method to understand the EOR mechanism. In this study, we designed and fabricated similarity models and microscopic visual models. The fluid flow mechanisms were discussed combining the pressure response and dynamic displacement phenomenon. Experimental results show that the effective time of nitrogen gas drive was longer in decreasing-aperture fractures than that in increasing-aperture fractures. After water flooding, 0.8 PV nitrogen gas injection lead to gas channeling in decreasing-aperture fracture of 1 mm–0.2 mm while 0.6 PV nitrogen gas injection by reverse displacement direction. Both production rate and average pressure appeared discrete in narrow fracture compared to wide fracture. Enhanced oil recovery efficiency by foam drive was average 5% higher than that by nitrogen gas drive in single fracture. The displacement front of foam varies in four forms: micro-scale foam accumulation, small-scale foam accumulation, mesoscale foam slight deformation and large-scale foam serious deformation. This study could provide a theoretical basis for enhance oil recovery and further dig the potential of remaining oil in fractured carbonate reservoirs. • Designed and Fabricated similarity models and microscopic visual models of varying-aperture fractures of carbonate reservoirs. • There is a synergistic effect of gas and water flooding in fractures, which promote to oil production by regulating the position of oil-water interface in fractures. • The displacement front of foam varies in four forms: micro-scale foam accumulation, small-scale foam accumulation, mesoscale foam slight deformation and large-scale foam serious deformation. [ABSTRACT FROM AUTHOR]

[Display omitted] • CO 2 responsive Janus SiO 2 nanofluid system was designed. • Crude oil emulsion breaks down after 5 min by CO 2 bubbling. • The response mechanism was proposed on the interfacial adsorption, rheological behavior and chemical properties. • Interfacial synergy behavior of JNPs, surfactants and asphaltenes was investigated. • Formation in-situ emulsification W/O Pickering emulsion control and flooding. Aiming to address the issues of limited suitability of conventional chemical oil displacement materials for formation conditions and the serious emulsification of oil and water in the produced liquid, the innovative nano oil-displacing system with CO 2 -responsive behavior has been developed. This system integrates oil displacement and emulsion breaking. The efficacy of the CO 2 -response system in creating stable emulsions with a high capacity to decrease interfacial tension has been demonstrated. The interfacial responsive behavior of all active components, including Janus nanoparticles, sodium oleate, gums, and asphaltenes, in the emulsion system was analyzed in terms of interfacial rheology and adsorption. Additionally, the prepared system demonstrated a rapid response to CO 2 , effectively breaking the emulsion within 5 min. Furthermore, the oil recovery enhancing mechanism of the CO 2 -response system was investigated using a microscopic visualization model. The system was proved to be efficient in initiating the residual oil within pore channels. Considering the combined effectiveness of the CO 2 -response system in terms of efficient oil displacement and rapid response, it offers valuable insights for advancing the chemical flooding technology of in enhanced oil recovery. [ABSTRACT FROM AUTHOR]

Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide owing to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. Here, the amphiphilic molybdenum disulfide nanosheets were synthesized through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of defects on the MoS 2 nanosheets surfaces. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS 2 nanosheets) are approximate 67 nm in width. The effects of ultralow concentration ODA-MoS 2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the laboratory displacement experiments were also carried out to reveal the adsorption rules and the oil displacement effects by using ultralow concentration ODA-MoS 2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 h after 50 mg/L ODA-MoS 2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 μm can be formed after the addition of ODA-MoS 2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS 2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS 2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS 2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% (OOIP) is achieved. Finally, the production performance of ultralow concentration of ODA-MoS 2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed. • A straightforward hydrothermal method is used to synthesize amphiphilic molybdenum disulfide nanosheets. • Amphiphilic MoS 2 can change the oil-wet solid surface into a neutral-wet solid surface and form micro-scale emulsions. • Core flooding experiments show excellent abilities in oil displacement efficiency (average 16.26%). • The applications of amphiphilic MoS 2 in Daqing oilfield have achieved excellent effects on oil production increase. [ABSTRACT FROM AUTHOR]

[Display omitted] • Amphiphilic molybdenum disulfide nanosheets can self-adsorb onto the oil-water interface to form a dense interface adsorption film. • The oil-water interface adsorption film exhibits excellent elastic properties and higher strength. • The oil-water interface adsorption film can intelligently control displacement front in porous media for enhanced oil recovery. Immiscible liquid-liquid interfaces have widespread applications in drug delivery, oil-water separation, oil recovery, emulsion and foam stability, etc. Here, a dense viscoelastic interface film is constructed via the self-adsorption of amphiphilic molybdenum disulfide nanosheets at the oil-water interface, which has significant implications for enhanced oil recovery. The microscopic dispersion characteristics of amphiphilic nanosheets in water phase are characterized using Cryo-EM, and the adsorption regularities of amphiphilic nanosheets in horizontal and vertical directions of oil-water interface are also revealed. Besides the mechanical response and rheological properties of interface adsorption film are systematically studied. Experimental results demonstrate that the amphiphilic nanosheet can self-curl to form a single amphiphilic nanosheet with a size of 30 nm in the water phase as the amphiphilic nanosheets concentration is lower than 50 mg/L. When the amphiphilic nanosheets concentration reaches 100 mg/L, obvious water-phase aggregation behaviors happen. The amphiphilic nanosheets can reduce the oil-water interfacial tension from 18.47 mN/m to 0.27 mN/m by forming multilayer adsorption at the oil-water interface. The adsorption ratio of amphiphilic nanosheets from bulk phase to oil-water interface can reach 97.50 %. In addition, the oil-water interface adsorption film exhibits excellent elastic properties and higher strength because the amphiphilic nanosheets can form a planar network structure at the oil-water interface which can be also directly observed in microfluidic pores. The storage modulus and interface shear viscosity of interface adsorption film are 1.65 Pa and 1.38 mN·s/m, respectively. In theory, the required desorption energy of a single amphiphilic nanosheet from oil-water interface to bulk phase is deduced to be 587 K B T. This work is expected to provide amphiphilic molybdenum disulfide nanosheet as an effective candidate for enhanced oil recovery. [ABSTRACT FROM AUTHOR]

• Alkylamine modified MoS 2 nanosheets are promising for enhanced oil recovery. • MoS 2 nanosheets alter the wettability of the core even at very low concentrations. • Residual oil recovery of 21.18% was obtained at 0.005 wt% of MoS 2 nanofluid. • MoS 2 can recover even heavy oil from low-permeability cores. Chemical enhanced oil recovery (C-EOR) agents, such as polymer and surfactants, have been used to recover residual oil from reservoirs. The investigation for finding more efficient and more economic agents has never been stopped. Here, we demonstrate the potential of two-dimensional MoS 2 nanosheets as a C-EOR agent. The synthesized amphiphilic MoS 2 nanosheets function as a surfactant by altering the wettability of the core even at very low concentrations. The laboratory core flooding experiments were performed in the man-made core samples with various permeabilities in range of 2.5–2500 mD saturated with crude oil (100 cP) and model oil (25 cP). The brine with the salinity of 98,171 mg/L is used for secondary flooding and nanofluid containing 0.005 wt% of nanosheets is used for tertiary flooding. We observe 21.18% and 18.25% of residual oil is recovered during tertiary flooding in 25 mD core samples saturated with model and crude oil respectively. This work reveals the new possibilities for economical production of oil using nanosheet based materials. [ABSTRACT FROM AUTHOR]

Highlights • A novel low IFT nanofluid for enhancing oil recovery is proposed. • The effect of IFT reduction and wettability alteration on imbibition is compared. • Dynamic inverse Bond Number is introduced to analyze the imbibition mechanism. Abstract Imbibition has been proposed as an important means by which to recover oil from low permeability reservoirs. However, the mechanism of imbibition enhanced oil recovery (IEOR) remains controversial. In this study, we attempted to explore these mechanisms using three of the most commonly used chemical systems (surfactant, brine based nano-silica, and surfactant based nano-silica solutions). First, the imbibition efficiency of the three systems was investigated through imbibition tests using Amott cells at 80 °C. Then, the interfacial tension (IFT) and contact angle were measured to explore the potential characteristics that may play important roles in IEOR. Finally, the dynamic inverse Bond number was introduced to further analyze the mechanisms of IEOR. The results show that oil recovery can be enhanced by 5.36% when using an ultra-low IFT surfactant solution, which has less ability to alter wettability; up to 4% using brine based nano-silica solutions, which can only alter wettability to more water-wet but cannot reduce the IFT; and 8.78% using surfactant based nano-silica solutions, which can both reduce the IFT and alter wettability effectively. Thus, both low IFT and good wettability alteration are desirable, and the highest recovery was achieved when both characteristics were combined, and maximizing their contributions to IEOR. This work firstly investigated the contribution of IFT reduction and wettability alteration on IEOR separately, and a novel system that produced excellent IEOR efficiency was formulated. This study provides fundamental information to the selection of IEOR chemicals. [ABSTRACT FROM AUTHOR]

To improve the dispersion stability of the nanofluid, SDS/Tween 60 surfactant solution was employed as the dispersant for the Janus SiO 2 nanofluid. The compounded system showed good dispersion stability and oil displacement effect at high temperature (90 ℃) and high salinity (35000 ppm). The amphiphilic Janus SiO 2 nanoparticle was synthesized by Pickering emulsion method. Next, by introducing SDS/Tween60 surfactant system as a dispersant agent, the Janus SiO 2 nanofluid could disperse well for more than 12 h at 90 ℃ with a salinity of 35000 ppm. The surfactant-enhanced Janus SiO 2 nanofluids showed good dispersion stability in different characterization methods, including visual observation, Turbiscan stability index (TSI) and particle size. Based on the adsorption experiments, the optimal mass concentration ratio between surfactant and Janus nanoparticles was fixed at 2:1. The possible dispersion and stability mechanism of Janus SiO 2 nanoparticles was explained from the perspective of the synergistic effect, between surfactants and nanoparticles and between surfactants and surfactants. Then, interfacial tension reduction ability, emulsion stability and wettability alternation capability of surfactant-enhanced Janus SiO 2 nanofluid with various concentrations, were studied at 90 ℃ with a salinity of 35000 ppm. The surfactant-enhanced Janus SiO 2 nanofluid, with a nanoparticle concentration of 0.01 wt%, showed the best EOR performance. The current study provides a new prospective in preparing Janus SiO 2 nanofluids applied for enhanced oil recovery in high temperature and high salinity reservoirs. [Display omitted] • The anionic/non-ionic surfactant system, SDS/Tween 60 (S/T), was employed as a dispersing agent for Janus SiO 2 nanofluids. • The surfactant-enhanced Janus SiO 2 nanofluids can maintain good dispersion stability at 90 ℃ with a salinity of 35000 ppm. • Addition of the S/T surfactants helps to enhance the interfacial properties of the Janus SiO 2 nanofluids. • The surfactant-enhanced Janus SiO 2 nanoparticles with the concentration of 0.01 wt% can increase the oil recovery by 15.3%. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition has been proved to be a promising enhanced oil recovery method for tight reservoirs, but the mechanisms of spontaneous imbibition oil recovery (SIOR) are still unclear. Here, we use the self-prepared novel lower-phase nano-emulsion (LWPNE) to reveal the mechanisms. In LWPNE solution, nano-scale oil drops (NODPs) in 6 nm diameter are formed and dispersed with co-presence of micelle solubilizing N-hexane. The effects of LWPNE on both interfacial tension (IFT) and contact angle were studied at 0–10,000 mg/L salinity condition, and spontaneous imbibition efficiency was determined from imbibition experiments in Amott cells at 60 °C. Electron Microscope and Transmission Electron Microscope were used to analyze the emulsification and solubilization mechanisms of LWPNE. Experimental results show that the original 135° (oil-wet) contact angle can be reduced to 32.7° (water-wet); the IFT is decreased to 0.0038 mN/m, and electrolyte has no contribution to either IFT reduction or wettability alteration. The average oil recovery from spontaneous imbibition testing using 0.3 wt% LWPNE is 44.1%, which is 20.5% higher than that from systems at similar conditions but using brine only. The LWPNE can solubilize oil by increasing NODPs' sizes to average 36 nm in diameter, which is the dominant mechanism to improve SIOR for LWPNE. The solubility of LWPNE is evaluated by the diameter growth rate of NODPs, and once it reaches 350%, a self-driving force drives oil drops to move forward. Moreover, the transformation mechanisms of spontaneous imbibition modes from imbibition to drainage are revealed by using the imbibition discriminant parameter (N B m − 1 ). • The nano-scale oil drops (NODPs) with a size of 6 nm in diameter are formed and evenly dispersed with co-presence of micelle solubilizing N-hexane. • The emulsification and solubilization effects of NODPs are discovered to be the dominant mechanisms for spontaneous imbibition oil recovery (SIOR). • A self-driving force (pressure difference at the curved interface) is proposed to drive oil drops moving forward during the solubilization processes. [ABSTRACT FROM AUTHOR]

• A pH-responsive emulsifier composed of SDS and EAB was proposed. • The interaction strength between SDS and EAB could be adjusted by regulation of pH. • The emulsions stabilized by SDS and EAB could demulsify once 0.1M HCl was added. In order to improve the recovery of crude oil and realize rapid demulsification of produced fluid, a pH-responsive zwitterionic/anionic surfactant system was proposed. The pH-responsive zwitterionic/anionic surfactant system consists of zwitterionic surfactant EAB (erucic amide carboxylic betaine) and anionic surfactant SDS (sodium dodecyl sulfate). By adjusting the pH value, the protonation degree of EAB could be controlled. Accordingly, the interaction between surfactants in the mixed system could be strengthened or weakened in neutral environment (pH = 6–8) or acidic conditions (pH = 2–4), respectively. In consequence, transformation between the emulsification and demulsification states for the emulsions stabilized by zwitterionic/anionic surfactant system could be effectively controlled by variation of the pH values. Meanwhile, the interfacial tension, average droplet size, microstructure and stability analysis of the mixed system emulsifying at various pH values were studied. For the emulsion stabilized by the pH-responsive zwitterionic/anionic surfactant system, the droplets size was evenly distributed and the average particle size was the lowest when the molar ratio of EAB to SDS was 4:6, whilst the average particle size increased significantly once the pH value was reduced down to 2 or 3. Above all, this study provides a new approach for the development of chemical flooding agents for enhancing oil recovery. [ABSTRACT FROM AUTHOR]

Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 °C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C 16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C 12 surfactants), which was mainly depending on better IFT reduction ability of C 16 surfactants than C 12 surfactants. Appropriate IFT reduction, such as 10−1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10−2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs. • The spontaneous imbibition efficiencies of different surfactant solutions based on molecular structures were investigated systematically. • The reasons for the imbibition efficiency differences of different solutions were investigated in detail. • The optimum surfactant types and IFTs suitable for imbibition were obtained. [ABSTRACT FROM AUTHOR]

Foam flooding is one of the enhanced oil recovery (EOR) techniques to minimize the gas mobility and improve the sweep efficiency. One of the major hindrances of foam flooding is the foam generation and stabilization under reservoir conditions. These difficulties were overcome by using the mixture of surfactant and nanoparticles which offers a stable foam under porous medium. This work examines the synergetic effect of foam generated by alpha olefin sulfonate (AOS) and MoS 2 nanosheets on the foamability and oil recovery performance. The generated foam is found to be stable in the presence of Ca2+ and Na+ ions. Also, the half-life of the foam is enhanced due to the formation of a protective layer around the foam lamellar by the nanosheets. The sandpack experiments were used to prove its enhanced oil recovery ability. The obtained results exhibit that the MoS 2 nanosheets stabilized foam has an incremental oil recovery. [ABSTRACT FROM AUTHOR]

• A comprehensive literature review was conducted on CO 2 -EOR in tight oil reservoirs. • Specialized technologies are needed in the exploitation of China's tight reservoirs. • The effect of CO 2 diffusion is relatively exaggerated in experimental results. • CO 2 -crude oil interaction in nanopores may lead to an oil recovery increment. • CO 2 -water-minerals interaction influences the geomechanical properties of rock. Primary oil recovery remains less than 10% in tight oil reservoirs, even after expensive multistage horizontal well hydraulic fracturing stimulation. Substantial experiments and simulation works have been performed to investigate CO 2 enhanced oil recovery (CO 2 -EOR) potential in tight reservoirs; however, some results conflict with each other. The objectives of this paper are to fully understand the CO 2 -EOR mechanisms and to figure out the difference between tight oil exploitation in North America and China through a comprehensive literature review. It is shown that compared with Bakken and Eagle Ford formation, China's tight oil reservoirs feature higher mud content and oil viscosity while they have a lower brittleness index of rock and formation pressure coefficient, leading to confined stimulated reservoir volume and further limited CO 2 -oil contact. The effect of CO 2 molecular diffusion is relatively exaggerated in experimental results, which can be attributed to the dual restrictions of exposure time and oil-CO 2 area in field scale. Numerical simulation works show that the shifted phase properties in nanopores lead to an oil recovery increment. The development of nano-scale chips withholding high pressure/temperature may advance the experimental study on the nanopore confinement effect. CO 2 -fluid-rock minerals interaction might be more complex due to the large specific surface area of nanopores in tight formations. The geomechanics coupling effect cannot be ignored when examining the CO 2 -EOR performance in tight reservoirs. And a comprehensive simulation study coupling with technical and economic feasibility is highly recommended before running a field test of CO 2 -EOR. [ABSTRACT FROM AUTHOR]

Emulsions, including oil-in-water (O/W) and water-in-oil (W/O) emulsions, can play important roles in both controlling reservoir conformance and displacing residual oil for enhanced oil recovery (EOR) projects. However, current methods, like high-shear mixing, high-pressure homogenizing, sonicators and others, often use lots of extra energy to prepare the emulsions with high costs but very low energy efficiency. In recent decades, spontaneous emulsification methods, which allow one to create micro- and nano-droplets with very low or even no mechanical energy input, have been launched as an overall less expensive and more efficient alternatives to current high extra energy methods. Herein, we primarily review the basic concepts on spontaneous emulsification, including mechanisms, methods and influenced parameters, which are relevant for fundamental applications for industrials. The spontaneity of the emulsification process is influenced by the following variables: surfactant structure, concentration and initial location, oil phase composition, addition of co-surfactant and non-aqueous solvent, as well as salinity and temperature. Then, we focus on the description of importance for emulsions in EOR processes from advances and categories to improving oil recovery mechanisms, including both sweep efficiency and displacement efficiency aspects. Finally, we systematically address the applications and outlooks based on the use of spontaneous emulsification in the practical oil reservoirs for EOR processes, in which conventional, heavy, high-temperature, high-salinity and low-permeability oil reservoirs, as well as wastewater treatments after EOR processes are involved. Unlabelled Image • Mechanisms, methods and influenced parameters for spontaneous emulsification are summarized. • Emulsion-based techniques for EOR are addressed based on displacement and sweep efficiencies. • Insightful applications and outlooks on spontaneous emulsification for EOR process in practical oil reservoirs are proposed. [ABSTRACT FROM AUTHOR]

The formation of a stable crude oil emulsion is of great significance for enhancing oil recovery in oilfield development. The effect of 1-octanol (C8OH) on the emulsifying properties of hydrophobically modified polyacrylamide (HMP) was studied based on a novel multiple light scattering method. The emulsions stabilized by different polymer systems were evaluated in terms of stability and rheological properties. The obtained results show that the combined system of HMP + C8OH gives more stable emulsion with smaller droplet size compared to individual HMP. There is a strong bulk and interface interaction between HMP and C8OH for stabilizing emulsions, while such effect was observed neither between partially hydrolyzed polyacrylamide and 1-octanol nor between HMP and 1-octane. In the bulk phase of aqueous solution, the C8OH can be solubilized in the micro-domains of HMP, enhancing the intermolecular association structure and slowing down the creaming rate of the corresponding emulsions. The adsorption at the oil-water interface of HMP can be enhanced and tighter interfacial film can be formed due to the formation of the hydrogen bond between HMP and C8OH. The obtained results are of obvious importance for designing the amphiphilic polymer-containing emulsion more suitable to improve oil recovery as well as for better understanding the self-assembling mechanism of amphiphilic polymers and fatty alcohols. [ABSTRACT FROM AUTHOR]