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Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs. [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]

Much attention has been directed toward amphiphilic nanosheets in diverse applications owing to their remarkable properties. In this work, the rhamnolipid-molybdenum disulfide nanosheets, environmentally friendly biological-amphiphilic-nanosheets (BANs), are prepared through the one-step simple hydrothermal method. The ultralow concentration of BANs (0.005 wt %), as a solid emulsifier, can emulsify crude oil and stabilize the size of emulsions (oil in water) within 1.2 μm. The adsorption of BANs to the oil–water interface improves the stability of the BANs emulsion, and it both reduces interfacial tension and increases interfacial film strength. Tremendous desorption energy (thousands of KBT) is required to remove a single BAN from the interface to the bulk phase. Besides, BANs can turn an oil-wet surface into an intermediate-wet surface and spread to exfoliate oil film on the solid surface. The evolution of the three-phase contact line experiences two stages: a steep stage and a gentle stage. The spreading behaviors are due to an imbalance between the surface forces and structuring disjoining pressure at the confinement region (wedge film). Moreover, 25.3% of additional oil recovery was observed from the flooding of an ultralow concentration of BANs nanofluid (0.005 wt %) in a natural outcrop core, which is 2.5 mD in permeability at experimental conditions: 120 °C and around 25 × 104 mg/L in salinity. The high tolerance of rhamnolipid-molybdenum disulfide nanosheets to high temperature and harsh salinity is because of synergism between MoS2 nanosheets and rhamnolipid molecules. Additional residual oil reduction is due to a combination of multiple effects such as crude oil emulsification, wettability alteration, interfacial tension reduction, and formation of structuring disjoining pressure. This study presents the possibility to enhance oil recovery in low-permeability reservoirs with harsh conditions. [ABSTRACT FROM AUTHOR]

Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N 2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N 2 foam flooding. When the injection volume of N 2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N 2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs. [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]

Fault-karst fractured-vuggy carbonate reservoir is an important type of fractured-vuggy carbonate reservoirs in Tahe oilfield of China. The fluids flow behaviors in fault-karst fractured-vuggy carbonate reservoir are complex and unclear due to the complexity of the connection between fractures and vugs. In this work, the novel 2D visual fault-karst fractured-vuggy carbonate reservoir physical models (longitudinal model and horizontal model) were designed and fabricated to investigate the flow characteristics and phase behaviors of nitrogen gas and foam-assisted nitrogen gas floods. Experimental results showed that oil-water and gas-oil interfaces fluctuations had positive effect on improving oil recovery. Foam-assisted nitrogen gas can effectively inhibit the occurrence of gas channeling, improve swept volume and increase oil recovery. A four-phase dimensionless index (Nr') was first proposed to describe the synergistic effects among the gas cap, foam cap and bottom water during foam-assisted nitrogen flooding process. Based on the analysis of oil recovery results, there was a turning point on oil recovery curve for foam-assisted nitrogen gas flooding. Moreover, the optimal production mode that was injection in high position of reservoir and recovery from low position of reservoir (HI-LR) in fault-karst carbonate reservoir was determined. This study is helpful to understand the flow characteristics of foam and nitrogen gas and provides a guide for increasing oil recovery in fault-karst fractured-vuggy carbonate reservoirs. • The novel 2D visual fault-karst fractured-vuggy carbonate reservoir physical models were designed and fabricated to investigate the flow characteristics and phase behaviors of nitrogen gas and foam-assisted nitrogen gas floods. • Foam-assisted nitrogen gas could effectively inhibit the occurrence of gas channeling, improve swept volume and increase oil recovery. • A four-phase dimensionless index (Nr') was proposed to describe the synergistic effects among the gas cap, foam cap and bottom water during oil recovery near the production well pores. • The optimal production mode of injection in high position of reservoir and recovery from low position of reservoir (HI-LR) in fault-karst carbonate reservoir was determined. [ABSTRACT FROM AUTHOR]

Reservoir heterogeneity and natural fractures greatly affect CO 2 flooding efficiency in ultra-low permeability oil reservoirs. CO 2 water alternating gas (WAG) flooding and the combinations of continuous CO 2 flooding and gas channeling treatments are recognized as effective approaches to improve CO 2 sweep efficiency. It is of major interest to propose the novel gas channeling treatments and conduct a feasibility study of different CO 2 -EOR technologies. Heterogeneous cores with different permeability ratios and fracture model were utilized in the laboratory experiments to simulate different types of heterogeneity in the oil reservoirs. Continuous CO 2 flooding, CO 2 WAG flooding, continuous CO 2 flooding+one-stage gas channeling control, and continuous CO 2 flooding+two-stage gas channeling control were conducted after water flooding in homogeneous and heterogeneous cores and fracture model. Ethylenediamine and modified starch gel were proposed as blocking agents to mitigate gas channeling. During the experiments, the CO 2 flooding efficiency was evaluated through the oil recovery increment, fluid mobility control and the changes of producing pressure drop. Experimental results show that producing pressure drop during continuous CO 2 flooding decreases rapidly with an increase in permeability ratio. Continuous CO 2 flooding cannot displace much of remaining oil in low permeability layers due to high mobility of CO 2 and serious heterogeneity. WAG flooding can effectively control the fluid mobility and improve CO 2 flooding efficiency when the permeability ratio is less or equal to 30. Plenty of remaining oil can be displaced by combining continuous CO 2 flooding and gas channeling treatments. When the permeability ratio is less or equal to 100, ammonium carbamate, the reaction product of injected ethylenediamine and CO 2 can block off high permeability layer and impel the injecting gas into low permeability layer. The two-stage injection of modified starch gel and etheylenediamine can significantly mitigate the gas channeling within high-capacity gas channel model and fracture model during continuous CO 2 flooding, and the incremental oil recovery could be more than 20%. Pilot test of CO 2 flooding was operated in Northwest China and concentrations of CO 2 are monitored in six production wells. Two kinds of construction plans for gas channeling treatments have been preliminary designed to control the gas channeling in the pilot. [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]