Global oil and gas resources are declining continuously, and sustainable development has become a common challenge worldwide. In terms of environmental protection and economic benefits, the application of microemulsions for enhanced oil recovery often requires fewer chemical agents, showing distinct advantages. This paper analyzes the application prospects and trends of middle-phase microemulsions in tertiary oil recovery. The properties of middle-phase microemulsions are introduced, and an overview of the historical development, theoretical framework, influencing factors, and preparation methods of emulsions are provided. From the perspective of oil displacement systems, this paper reviews the selection and characterization methods of emulsions, as well as the interaction mechanisms between emulsions and reservoirs, proposing future research directions. The focus of the paper is on the evaluation and characterization of emulsions, the mechanisms of micro-oil displacement, and the application of advanced CT scanning technology, which gives a new understanding of wettability changes, capillary forces, and miscible solubilization processes, contributing to the reduction in displacement costs and the improvement of economic benefits. In conclusion, the middle-phase microemulsion flooding technique can significantly enhance oil recovery through the comprehensive action of various mechanisms and has been widely used in oil field development.

Summary: Hydraulic fracturing is an effective stimulation method to establish high-conductivity channels in tight reservoirs, and the effectiveness of man-made fractures largely depends on the proppant-carrying capacity of the fracturing fluids used. As a novel completion fluid, silica gel-based fracturing fluids have shown desirable stimulation effect in application cases, but a comprehensive evaluation of their proppant settling and transport behaviors in the laboratory remains lacking. In this paper, a silica gel-based fracturing fluid was prepared first, and then the rheological properties, including shear thinning, recovery behavior, and viscoelasticity of the fluid system, were measured. Afterward, the settling velocity of single-particle proppant and the settling rate of multiparticle proppant under various experimental conditions were investigated in the static fluid system; in addition, the dynamic proppant-carrying performance was evaluated using a visualized rough fracture model to study different factors on the dune distribution inside the fractures. Lastly, the proppant-carrying mechanism of silica gel-based fracturing fluid was revealed in three aspects. The rheological test result showed that the shear viscosity of silica gel-based fracturing fluid increased as the SiO2 concentration increased. Furthermore, all tested fluid samples exhibited an elastic modulus that is consistently greater than the viscous modulus, indicating that the silica gel-based fracturing fluid system has a dominant elastic response behavior. In the single-particle static settling test, there was a significant increase in the settling velocities as the particle diameter increased and as the temperature increased. Meanwhile, the settling rate of multiparticles showed a decreasing trend with the increase in mesh size, while the proppant settling rate gradually increased as the proppant concentration rose. The results of dynamic proppant-carrying experiments demonstrate that a higher pumping rate leads to an extended migration distance for proppant, resulting in formed sand dunes with reduced height within fractures. Conversely, an increase in proppant concentration and a reduction in mesh size tend to form higher sand dunes. The proppant-carrying mechanisms of the silica gel-based fracturing fluid relate to the self-polymerization and syneresis of silica gel, the noticeable elasticity characteristics, and the structural encapsulation effect formed between silica gel and proppant. A better understanding of the proppant settling and transport behaviors of silica gel-based fracturing fluid can be helpful in optimizing the hydraulic fracturing design and promoting field application.

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.

Uniform acidizing has been an urgent challenge in strongly heterogeneous and high-temperature carbonate reservoirs. Nanoparticles have been shown to enhance the viscosity of viscoelastic-surfactant (VES) fracturing fluids, thereby improving the proppant carrying capacity of the fluid. However, there is almost no understanding of the nanoparticles on wormhole propagation and diversion in VES acid at low pH values and high salinity. Here, the rheological and adsorption model of nanoparticles in VES acid are established based on experimental results, and the multi-field and multi-scale coupling model of nanoparticles-VES acid is established by introducing the temperature field and two-scale continuum model. Based on the model, the propagation pattern and diverting performance of the wormholes were analyzed. The effects of permeability contrast, temperature, and adsorption on the propagation pattern and diverting performance are systematically investigated. The results show that the synergistic effect of nanoparticles and adsorption divided the invaded zone of spent acid into high-viscosity and low-viscosity zones, and the propagation capacity of the wormholes in the low-permeability reservoir was increased by 17%. The propagation and diverting process of wormholes can be divided into three stages. In stage II, when the additional resistance increased by spent acid is enough to resist the permeability contrast and the wormholes, more acid starts to flow into the low-permeability reservoir. The higher flow rate in the high-permeability reservoir makes the propagation path more complicated, and more branching wormholes are formed. At a reservoir temperature of 393 K, the nanoparticle-VES acid has the poor diverting ability for reservoirs with permeability contrast greater than ten. When the maximum adsorption capacity is 0.008 mol/kg, the diverting performance of nanoparticle-VES acid and VES acid were close. Reducing the adsorption is a very effective way to enhance the diverting performance. When the adsorption capacity is larger, the influence distance of the high viscosity zone formed by the dominant wormholes is limited, and the number of main wormholes in the reservoir becomes significantly large. This study clarifies the propagation law and diverting characteristics of wormholes using nanoparticle-VES acid, fills the technical gap of nanoparticles in acidizing, and provides guidance and a basis for the stimulation of uniform acidizing in high-temperature carbonate.

Summary: Driven by the depletion of conventional reservoirs and the escalating global energy demand, the focus has shifted toward unconventional reservoirs. These reservoirs exhibit intricate fluid flow behaviors due to their lower permeability and smaller pore sizes compared with conventional reservoirs. Traditional characterization techniques, such as nitrogen adsorption and mercury injection capillary pressure (MICP), are significantly limited in accurately characterizing fluid flow in these complex reservoirs. Nuclear magnetic resonance (NMR) emerges as a nondestructive and highly precise method, providing valuable insights into fluid-rock interactions, pore-size distribution, and fluid identification at the pore scale. This study investigates the behavior of typical oleic and aqueous fluids, including both single-component and multicomponent fluids, in both conventional and unconventional reservoirs. The 1D and 2D NMR properties of these fluids are characterized in both bulk state and porous media. The impacts of fluid composition and pore size on T1, T2, and T1–T2 spectra are examined to distinguish NMR behaviors in nanoscale and microscale pores. In the bulk fluid state, 1D NMR reveals that T1 and T2 spectral peaks decrease with increasing fluid viscosity. Meanwhile, T1–T2 spectra show that fluids with different viscosities are distributed within a T1/T2 ratio range of 0.5–2, shifting leftward and downward as viscosity increases. In porous media, increased fluid viscosity causes a leftward shift in T1 and T2 spectra, consistent with bulk fluid behavior. In high-permeability cores (HPCs), T1 and T2 spectra of single- and multicomponent fluids exhibit unimodal distributions, aligning with pore size distribution. In contrast, in low-permeability cores (LPCs), T1 spectra of all fluids remain unimodal, while T2 spectra of multicomponent fluids become bimodal due to diffusion relaxation effects. This is attributed to differences in diffusion coefficients and enhanced internal gradient fields in nanoscale pores. Thus, T1 spectra are more suitable for characterizing multicomponent fluid distribution in low-permeability reservoirs with nanoscale pores. Core centrifugation tests combined with NMR scans are used to assess fluid mobility changes influenced by viscosity and centrifugal pressure. For fluid mobility in different porous media, cutoff values of T1 and T2 and movable fluid saturations are determined through centrifugation tests. The deviation of T2 spectra from the real pore structure does not affect the calculation of movable fluid saturation. However, T1 spectra provide a more accurate representation of fluid distribution during centrifugation, despite longer measurement times. This study validates the adaptability of 1D NMR for characterizing the pore structure and fluid distribution of unconventional reservoirs. It provides a reliable reference for multifluid identification in real underground conditions. The study enhances the understanding of fluid behavior and pore-scale interactions in complex reservoirs and offers a robust framework for optimizing NMR applications in unconventional reservoirs.

Uniform acid distribution is a critical challenge and a key factor for the successful acidizing of carbonate reservoirs. Previous experimental studies have shown that nanoparticles can enhance the viscosity and thermal resistance of viscoelastic surfactant (VES) fracturing fluids. However, there has been limited research on the effects of nanoparticles on the wormhole propagation and diversion performance of VES acid. This paper establishes a nanoparticle VES acid rheological model based on rheology experiments, and introduces a porous medium temperature field and nanoparticle adsorption model into a two-scale continuum model to establish a mathematical model for the expansion of wormholes in nanoparticle VES acid. The accuracy of the wormhole model is verified through laboratory experiments. The effects of permeability contrast, initial acid temperature, and nanoparticle adsorption on the diversion performance and wormhole propagation of nanoparticle VES acid are analyzed. The results indicate that nanoparticle VES acid differs from conventional VES acid, with its invaded zone divided into high-viscosity and low-viscosity zones. The presence of the high-viscosity zone allows nanoparticle VES acid to improve wormhole propagation in low-permeability cores by 16.2% compared to conventional VES acid. At 393 K, nanoparticle VES acid has a better diversion effect in carbonate cores with permeability contrast of 10, as the acid fluid flows faster in high-permeability cores, resulting in wormhole shapes with more branches. Numerical model results show that when the permeability contrast is 8, increasing the injection temperature of the acid solution from 293 K to 368 K improves the ability of low-permeability cores by 33.3%. This study establishes a mathematical model for nanoparticle VES acid based on laboratory experiments and numerical simulations, investigates the effects of nanoparticles on VES rheological properties under acidic conditions, and clarifies the wormhole propagation and acid diversion behavior of nanoparticle VES acid, providing guidance for future field applications of this acid.