With the increasing exploration and development of deep shale gas resources, water-based fracturing fluids face multiple challenges, including high-temperature resistance, salt tolerance, and efficient proppant transport. In this study, a zwitterionic polymer (polyAMASV) is synthesized via aqueous two-phase dispersion polymerization, using acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), acrylic acid (AA), stearyl methacrylate (SMA), and 4-vinylpyridine propylsulfobetaine (4-VPPS) as monomers. The introduction of hydrophobic alkyl chains effectively adjusts the viscoelasticity of the emulsion, while the incorporation of zwitterionic units provides salt tolerance through their intrinsic anti-polyelectrolyte effect. As a result, the solutions of such copolymers exhibit stable apparent viscosity in both NaCl and CaCl₂ solutions and under high temperatures. Meanwhile, polyAMASV outperforms conventional samples across various saline environments, reducing proppant settling rates by approximately 20%. Moreover, the solutions exhibit rapid gel-breaking and low residue characteristics, ensuring effective reservoir protection. These results highlight the promising potential of polyAMASV for deep shale gas fracturing applications.

Polymer flooding has been gradually applied in Chinese offshore oilfields to enhance oil recovery (EOR). Injectivity loss during polymer flooding is a common issue that could cause lower displacement speed and efficiency, and eventually compromise the polymer flooding result. This paper presents a case study of a Chinese offshore field where injectivity loss issues were encountered in the polymer flooding project. A series of measures are applied to enhance the injectivity. The injectivity enhancement strategies are proposed and conducted from three main aspects, namely, (1) surface polymer fluid preparation; (2) downhole wellbore stimulation; and (3) reservoir–polymer compatibility, respectively. For the surface polymer fluid preparation, a series of sieve flow tests are conducted to obtain the optimal mesh size to improve the polymer fluid preparation quality and reduce the amount of “fish eyes”. The downhole wellbore stimulations involve oxidization-associated acidizing treatment and re-perforation. Polymer–reservoir compatibility tests are conducted to optimize the molecular weight (MW). Regarding the surface measures, the optimal filtration sieve mesh number is 200, which could reduce fish eyes to a desirable level without causing mesh plugging. After mesh refinement, the average injection pressure of the twelve injection wells decreases by 0.5 MPa. For the downhole stimulations, acidizing treatment are applied to six injection wells, which decreases the injection pressures by 6 to 7 MPa. For Well A, where acidizing does not work, the re-perforation measure is used and enhances the injectivity by 300%. Moreover, the laboratory and field polymer–reservoir compatibility tests show that the optimal polymer molecular weight (MW) is sixteen million. Proposed strategies applied from the surface, downhole, and reservoir aspects could be used to resolve different levels of injectivity loss, which could provide guidance for future offshore polymer projects.

Effectively enhancing oil recovery can be achieved by reducing the viscosity of crude oil. Therefore, this paper investigated the viscosity reduction behavior of carbon nanotube viscosity reducers with different molecular structures at the oil–water interface, aiming to guide the synthesis of efficient viscosity reducers based on molecular structure. This study selected carbon nanotubes with different functional groups (NH₂-CNT, OH-CNT, and COOH-CNT) for research, and carbon nanotubes with varying carbon chain lengths were synthesized. These were then combined with Tween 80 to form a nanofluid. Scanning electron microscopy analysis revealed an increased dispersibility of carbon nanotubes after introducing carbon chains. Contact angle experiments demonstrated that -COOH exhibited the best hydrophilic effect. The experiments of zeta potential, conductivity, viscosity reduction, and interfacial tension showed that, under the same carbon chain length, the conductivity and viscosity reduction rate sequence for different functional groups was -NH₂ < -OH < -COOH. The dispersing and stabilizing ability and interfacial tension reduction sequence for different functional groups was -COOH < -OH < -NH₂. With increasing carbon chain length, conductivity and interfacial tension decreased, and the viscosity reduction rate and the dispersing and stabilizing ability increased. Molecular dynamics simulations revealed that, under the same carbon chain length, the diffusion coefficient sequence for different functional groups was -NH₂ < -OH < -COOH. The diffusion coefficient gradually decreased as the carbon chain length increased, resulting in better adsorption at the oil–water interface. This study holds significant importance in guiding viscosity reduction in heavy oil to enhance oil recovery.

Formation water scale blocks pipelines and results in oil/gas production decreasing and energy consumption increasing. Many methods have been developed to inhibit scale formation. However, these previous methods are limited by their complications and low efficiency. A new method is proposed in this paper that uses the scale in formation water as a nanomaterial to improve oil recovery via controlling particle size. A series of ligands were synthesized and characterized. Micrometer-CaCO₃ was formed and accumulated to form scale of a large size under uncontrolled conditions. The tetradentate ligands (L⁴) exhibited an excellent capturing yield of Ca²⁺ (87%). The particle size was very small, but they accumulated to form large particles (approximately 1300 nm) in the presence of Na₂CO₃. The size of the CaCO₃ could be further controlled by poly(aspartic acid) to form sizes of about 700 nm. The flooding test showed that this material effectively improved oil recovery from 55.2% without nano CaCO₃ to 61.5% with nano CaCO₃. This paves a new pathway for the utilization of Ca²⁺ in formation water.

High-internal-phase water-in-oil (W/O) emulsions generated in situ have garnered considerable attention as novel profile control systems. However, conventional emulsifiers are unreactive and poorly dispersed in water, necessitating large dosages and resulting in poor injectivity. In this study, we synthesized amphiphilic nanoparticles (SiO₂–NH₂–DAC NPs) containing amine and long-chain alkyl groups using a one-pot method and investigated the stabilized emulsion properties. Our results indicated that W/O emulsions with a water-to-oil ratio (WOR) of 7:3 to 8:2 could be prepared with just 0.1 wt% of SiO₂–NH₂–DAC NPs under neutral and basic conditions, with demulsification occurring under acidic conditions (pH = 2.1), demonstrating the pH-responsiveness of the W/O emulsions. The emulsion viscosity increased from 150 to 2555 mPa·s at different WORs. An additional 18.7% oil recovery was achieved using SiO₂–NH₂–DAC NPs in a heterogeneous core, highlighting their potential as a promising profile control candidate.

Nuclear magnetic resonance (NMR) and high-pressure mercury injection (HPMI) have been widely used as common characterization methods of pore-throat. It is generally believed that there is a power function relationship between transverse relaxation time (T₂) and pore-throat radius (r), but the segmentation process of the pore-throat interval is subjective, which affects the conversion accuracy. In this paper, ordered clustering is used to improve the existing segmentation method of the pore-throat interval, eliminate the subjectivity in the segmentation process, and obtain a more accurate distribution curve of the pore-throat. For the three kinds of cores with ordinary-low permeability (K > 1 mD), ultra-low permeability (0.1 mD < K < 1 mD), and super-low permeability (K < 0.1 mD), the pore-throat distribution curves of the cores were obtained by using the improved T₂ conversion method. Then, the oil and gas two-phase displacement experiment was carried out to investigate the degree of recovery and cumulative gas–oil ratio changes during the displacement process. Finally, the converted T₂ spectrum was used to quantify the utilization of different pore sizes. The improved T₂ conversion method not only has better accuracy but also is not limited by the pore-throat distribution types (such as unimodal, bimodal, and multi-modal, etc.) and is suitable for any core with measured HPMI pore-throat distribution and an NMR T₂ spectrum. Combined with the results of core displacement and the degree of pore-throat utilization, it is found that the potential of miscible flooding to improve the recovery degree is in the order of ordinary-low permeability core (18–22%), ultra-low permeability core (25–29%), and super-low permeability core (8–12%). The utilization degree of immiscible flooding to the <10 nm pore-throat is low (up to 35%), while miscible flooding can effectively use the <3.7 nm pore-throat (up to 73%). The development effect of supercritical CO₂ flooding on K < 0.1 mD reservoirs is not good, the seepage resistance of CO₂ is large, the miscible flooding makes it difficult to improve the recovery degree, and the utilization effect of pore-throat is poor.